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 June 30, 1999
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 July 30, 1999 there
were outstanding 11,463,019 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 six months ended June 30, 1999 and 1998 3
Consolidated Balance Sheet as of June 30, 1999 and
December 31, 1998 4
Consolidated Statement of Cash Flows for the six
months ended June 30, 1999 and 1998 5
Notes to Consolidated Financial Statements 6-15
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 16-39
PART II. OTHER INFORMATION 40-41
SIGNATURE 42
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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 Six Months Ended
June 30 June 30
1999 1998 1999 1998
<S> <C> <C> <C> <C>
Operating Revenues $93,139 $66,406 $191,781 $150,364
Operating Expenses
Operation
Purchased power 62,899 45,882 112,934 85,588
Production and transmission 5,761 5,766 10,760 11,354
Other operation 11,195 11,419 23,234 22,853
Maintenance 4,156 3,802 7,040 7,654
Depreciation 4,212 4,231 8,397 8,458
Other taxes, principally property taxes 2,815 2,804 5,902 5,844
Taxes on income 238 (3,419) 7,795 2,013
------ ------- ------- -------
Total operating expenses 91,276 70,485 176,062 143,764
------ ------- ------- -------
Operating Income (Loss) 1,863 (4,079) 15,719 6,600
------ ------- ------- ------
Other Income and Deductions
Equity in earnings of affiliates 760 844 1,505 1,576
Other income, net 326 365 1,290 960
Benefit (provision) for income taxes (17) 52 (262) 62
------- ------- ------- -----
Total other income and deductions, net 1,069 1,261 2,533 2,598
------- ------- ------- -----
Total Operating and Other Income (Loss) 2,932 (2,818) 18,252 9,198
Net Interest Expense 2,516 2,634 5,106 5,259
------- ------- ------ ------
Net Income (Loss) Before Extraordinary
Credit 416 (5,452) 13,146 3,939
Extraordinary Credit Net of Taxes - - - 873
------- ------- ------ ------
Net Income (Loss) 416 (5,452) 13,146 4,812
Retained Earnings at Beginning of Period 80,013 85,613 67,748 75,841
------ ------- ------ -------
80,429 80,161 80,894 80,653
Cash Dividends Declared
Preferred stock 466 487 931 973
Common stock 2,527 5,028 2,527 5,034
------- ------- ----- ------
Total dividends declared 2,993 5,515 3,458 6,007
------- ------- ------ ------
Retained Earnings at End of Period $77,436 $74,646 $ 77,436 $ 74,646
======= ======= ======== ========
Earnings (Losses) Available For
Common Stock $ (50) $(5,939) $ 12,215 $3,839
Average Shares of Common Stock
Outstanding 11,462,417 11,425,725 11,461,778 11,424,843
Basic and Diluted Share of Common Stock:
Earnings (losses) before extraordinary
credit $ .00 $(.52) $1.07 $ .26
Extraordinary credit - - - .08
------ ------- ------ ------
Earnings (Losses) Per Basic and Diluted
Share of Common Stock $ .00 $(.52) $1.07 $ .34
====== ====== ===== ======
Dividends Paid Per Share of Common Stock $.22 $.22 $.44 $.44
The accompanying notes are an integral part of these consolidated financial statements.
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<TABLE>
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED BALANCE SHEET
(Dollars in thousands)
(Unaudited)
June 30 December 31
1999 1998
<S>
Assets <C> <C>
Utility Plant, at original cost $473,574 $469,204
Less accumulated depreciation 167,967 160,666
-------- --------
305,607 308,538
Construction work in progress 9,450 10,461
Nuclear fuel, net 1,391 948
-------- --------
Net utility plant 316,448 319,947
-------- --------
Investments and Other Assets
Investments in affiliates, at equity 25,900 26,142
Non-utility investments 36,193 35,896
Non-utility property, less accumulated depreciation 2,741 2,920
-------- --------
Total investments and other assets 64,834 64,958
-------- --------
Current Assets
Cash and cash equivalents 19,277 10,051
Special deposits 394 424
Accounts receivable, less allowance for uncollectible
accounts ($1,107 in 1999 and $2,242 in 1998) 33,126 29,224
Unbilled revenues 13,153 18,677
Materials and supplies, at average cost 3,600 3,746
Prepayments 1,805 1,881
Other current assets 5,954 9,768
-------- --------
Total current assets 77,309 73,771
-------- --------
Regulatory Assets 60,691 66,719
-------- --------
Other Deferred Charges 4,819 4,887
-------- --------
Total Assets $524,101 $530,282
======== ========
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 45,329 45,318
Accumulated other comprehensive income (365) (365)
Treasury stock (322,829 shares and
324,717 shares, respectively, at cost) (4,209) (4,234)
Retained earnings 77,436 67,748
-------- --------
Total common stock equity 188,906 179,182
Preferred and preference stock 8,054 8,054
Preferred stock with sinking fund requirements 17,000 18,000
Long-term debt 90,066 90,077
Capital lease obligations 15,601 16,141
-------- --------
Total capitalization 319,627 311,454
-------- --------
Current Liabilities
Short-term debt 32,000 37,000
Current portion of long-term debt and preferred stock 4,023 6,773
Accounts payable 14,810 11,589
Accounts payable - affiliates 10,850 11,784
Accrued income taxes 1,318 2,975
Dividends declared 466 2,521
Nuclear decommissioning costs 4,820 4,820
Disallowed purchased power costs 3,680 7,361
Other current liabilities 16,671 17,403
-------- --------
Total current liabilities 88,638 102,226
-------- --------
Deferred Credits
Deferred income taxes 48,627 47,581
Deferred investment tax credits 6,635 6,831
Nuclear decommissioning costs 21,045 23,239
Other deferred credits 39,529 38,951
-------- --------
Total deferred credits 115,836 116,602
-------- --------
Total Capitalization and Liabilities $524,101 $530,282
======== ========
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)
Six Months Ended
June 30
1999 1998
<S> <C> <C>
Cash Flows Provided (Used) By
Operating Activities
Net income $13,146 $4,812
Adjustments to reconcile net income to net cash
provided by operating activities
Equity in earnings of affiliates (1,505) (1,576)
Dividends received from affiliates 1,697 1,312
Equity in earnings of non-utility investments (1,520) (3,046)
Distribution of earnings from non-utility
investments 2,758 1,663
Extraordinary credit - (1,294)
Depreciation 8,397 8,458
Deferred income taxes and investment tax credits 1,499 2,928
Net deferral and amortization of nuclear refueling
replacement energy and maintenance costs 1,377 (4,168)
Amortization of conservation and load management
costs 3,304 3,509
Amortization of capital leases 541 541
Decrease in accounts receivable and unbilled
revenues 1,400 9,560
Increase in accounts payable 2,514 315
Decrease in accrued income taxes (1,657) (10,352)
Change in other working capital items (122) (6,394)
Other, net 1,070 670
------- -------
Net cash provided by operating activities 32,899 6,938
------- -------
Investing Activities
Construction and plant expenditures (5,817) (6,935)
Conservation & load management expenditures (1,547) (1,195)
Return of capital 93 93
Non-utility investments (1,601) (100)
Other investments, net (10) (178)
Net cash used for investing activities (8,882) (8,315)
------- -------
Financing Activities
Short-term debt, net (8,750) (400)
Long-term debt, net (11) (10)
Common and preferred dividends paid (5,509) (5,513)
Reduction in capital lease obligations (541) (541)
Sale of common stock 20 112
-------- --------
Net cash used for financing activities (14,791) (6,352)
-------- --------
Net Increase (Decrease) in Cash and Cash Equivalents 9,226 (7,729)
Cash and Cash Equivalents at Beginning of Period 10,051 16,506
-------- --------
Cash and Cash Equivalents at End of Period $19,277 $ 8,777
======== ========
Supplemental Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) $ 4,953 $ 5,106
Income taxes (net of refunds) $ 8,213 $ 9,777
The accompanying notes are an integral part of these consolidated financial statements.
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
Note 1 - Accounting Policies
The Company's significant accounting policies are described in Note 1 of
Notes to Consolidated Financial Statements included in its 1998 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.
RECLASSIFICATION Certain reclassifications have been made to prior year
Consolidated Statement of Cash Flows to conform with the 1999 presentation.
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, 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
(PRPs). 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.
A reserve of $9.9 million has been established representing management's
best estimate of the costs to remediate these 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
On September 22, 1997, the Company filed with the Public Service Board, or
PSB, for a 6.6% or $15.4 million retail 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. At the
same time, the Company also filed a request to eliminate the then current
differential between the rates charged customers in the summer and the rates
charged customers in the winter and price electricity the same year-round.
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 Department of Public
Service, or 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 recently
argued its position before the Vermont Supreme Court. The Vermont Supreme
Court has not rendered a decision, but a decision by the end of 1999 is
possible.
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 Vermont Joint Owners, or VJO,
Power Contract presently before the Vermont Supreme Court. 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 Vermont Supreme Court. As a result of the 4.7% rate increase
agreement, during the fourth quarter of 1998, the Company recorded a pre-tax
loss of $7.4 million for disallowed purchased power costs, representing the
Company's estimated under-recovery of power costs under the VJO Power Contract
for calendar year 1999.
This temporary $7.4 million disallowance was calculated using comparable
methodology to that used by the PSB in the Green Mountain Power rate case on
February 28, 1998. In that case, the PSB found Green Mountain Power'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 Green Mountain Power's current costs should not be
imposed on Green Mountain Power's customers and were disallowed. Green Mountain
Power 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.
Assuming an unfavorable Vermont Supreme Court ruling and depending on the
methodology subsequently used by the PSB to determine the amount of any
disallowance, the amount of any permanent disallowance could be more or less
than the $7.4 million temporary disallowance. However, if the Company receives
an unfavorable ruling from the Vermont Supreme Court 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 $205.0 million of power costs over the life of the contract,
including $11.5 million in 2000, $11.6 million in 2001, $11.7 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
$205.0 million (pre-tax). Such an outcome could jeopardize the Company's
ability to continue as a going concern.
New Hampshire Retail Rate Proceedings
Connecticut Valley Electric Company Inc.'s, or Connecticut Valley's,
retail rate tariffs, approved by the New Hampshire Public Utilities Commission,
or NHPUC, contain a Fuel Adjustment Clause, or FAC, and a Purchased Power Cost
Adjustment, or PPCA. Under these clauses, Connecticut Valley recovers its
estimated annual costs for purchased energy and capacity which are reconciled
when actual data is available.
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 deter-
mination on the FAC and PPCA rates should be reconciled back to January 1, 1998
or some other date.
Federal Court Proceedings
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 January 19, 1998, Connecticut Valley and the Company filed with the
Federal District Court, or 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 the Federal Energy
Regulatory Commission's, or FERC 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, "Accounting for the
Effects of Certain Types of Regulation." 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
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 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 Public Service Company of New Hampshire, or 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, 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
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 United States First Circuit Court of Appeals, or
Court of Appeals.
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 rate
of $.008 per KWH and the proposed PPCA rate of $.01000 per KWH, 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 and 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 also 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. Company management,
however, continues to believe that the NHPUC's actions are illegal and
unconstitutional and will present its arguments in the appropriate forum.
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 if 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. A briefing schedule has been established that extends
into early October 1999.
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. No further action has
been scheduled by the Court.
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,
1999, is approximately $48.0 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 later this year, and the FERC will act on
the judge's recommendations sometime thereafter.
If the Company is unable to obtain an order authorizing the recovery of
costs in connection with the June 1997 FERC filing, the Company would be
required to recognize a pre-tax loss under this contract totaling
approximately $60.0 million on a pre-tax basis. The Company would also be
required to write-off approximately $4.0 million (pre-tax) in regulatory
assets associated with its wholesale business. The cash flow shortfall from
the revenues would be approximately $6.0 million (pre-tax) annually. 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 $48.0 million (pre-tax)
representing future underrecovery of power costs.
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
The Company adopted SFAS No.131,"Disclosures about Segments of an
Enterprise and Related Information," effective for financial statements for
periods beginning after December 15, 1997. 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, or Central Vermont which engages in the purchase,
production, transmission, distribution and sale of electricity in Vermont;
Connecticut Valley Electric Company Inc., or Connecticut Valley which
distributes and sells electricity in parts of New Hampshire; and Catamount
Energy Corporation, or Catamount which has investments is energy generation
projects in the United States and Great Britain. Connecticut Valley, while
managed on an integrated basis with Central Vermont, is presented separately
because of its separate and distinct regulatory jurisdiction. Other operating
segments include segments below the quantitative threshold for separate
disclosure. These operating segments are SmartEnergy Services, Inc. which
invests in unregulated energy and service related businesses, and C. V.
Realty, Inc., a real estate company whose purpose is to own, acquire, buy,
sell and lease real and personal property and interests therein related to the
utility business.
The accounting policies of the operating segments are the same as those
described in Note 1 to Consolidated Financial Statements included in the
Company's 1998 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.
Financial information by industry segment for the three and six months ended
June 30, 1999 and 1998, is as follows (dollars in thousands):
<TABLE>
<CAPTION>
Reclassifications
Central Vermont Connecticut Valley All & Consolidating
Vermont New Hampshire Catamount Other<F1> Entries Consolidated
--------------- ------------------ -------- ------- ----------------- ------------
<S> <C> <C> <C> <C> <C> <C>
Three Months Ended June 30
1999
Revenues from external
customers $ 88,221 $ 4,918 $ 166 $ 1,966 $2,132 $ 93,139
Intersegment revenues 3,132 - - - 3,132 -
Net income (loss) 248 271 308 (411) - 416
Total assets 468,220 12,639 43,954 5,083 5,795 524,101
1998
Revenues from external
customers $ 60,922 $ 5,485 $ 66 $ 475 $ 542 $ 66,406
Intersegment revenues 3,331 - - - 3,331 -
Net income (loss) (5,567) (9) 536 (412) - (5,452)
Total assets 462,714 13,773 41,459 2,846 5,242 515,550
</TABLE>
<TABLE>
<CAPTION>
Reclassifications
Central Vermont Connecticut Valley All & Consolidating
Vermont New Hampshire Catamount Other<F1> Entries Consolidated
-------------- ----------------- --------- -------- ---------------- ------------
<S> <C> <C> <C> <C> <C> <C>
Six Months Ended June 30
1999
Revenues from external
customers $180,480 $11,303 $ 295 $ 4,288 $4,585 $191,781
Intersegment revenues 6,455 - - - 6,455 -
Net income (loss) 12,459 324 913 (550) - 13,146
Total assets 468,220 12,639 43,954 5,083 5,795 524,101
1998
Revenues from external
customers $139,216 $11,149 $ 133 $ 947 $1,081 $150,364
Intersegment revenues 6,774 - - - 6,774 -
Net income (loss) before
extraordinary credit (60) 3,584 1,275 (860) - 3,939
Net income (loss) (60) 4,457 1,275 (860) - 4,812
Total assets 462,714 13,773 41,459 2,846 5,242 515,550
<F1> 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:
Three Months Ended Six Months Ended
June 30 June 30
1999 1998 1999 1998
Operating revenues $46,376 $57,913 $90,153 $109,083
Operating income $ 3,607 $ 3,950 $ 7,393 $ 7,710
Net income $ 1,638 $ 1,806 $ 3,294 $ 3,508
Company's equity in net income $523 $539 $ 1,041 $ 1,049
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
June 30, 1999
Earnings Overview
The Company recorded losses available for common stock of $50,000 and
$5.9 million for the three months ended June 30, 1999 and 1998, respectively.
Losses per share of common stock for these periods were $.00 and $.52,
respectively. Due to the Company's winter sales peak and higher winter rates,
the Company normally experiences losses in the second and third quarters when
sales are lower and rates are reduced.
Improved second quarter 1999 earnings resulted from lower net power costs
primarily associated with better performance at Millstone Unit No. 3 and
Vermont Yankee nuclear power plant.
For the six months ended June 30, 1999, earnings available for common
stock were $12.2 million compared to $3.8 million in 1998. Earnings per share
of common stock for these respective periods were $1.07 and $.34.
Increased earnings for the first six months of 1999 reflect the positive
impact of a 4.7% temporary Vermont rate increase ($3.8 million after-tax, or
$.33 per share of common stock) as well as a 2.2% increase in retail MWH
sales. Other factors affecting results for 1999, including the positive
affect of lower net power costs, are described in Results of Operations below.
The 1998 first six months reflects the positive impact of reversing
Connecticut Valley Electric Company Inc.'s, or Connecticut Valley's fourth
quarter 1997 after-tax charges of $4.5 million or $.39 per share of common
stock.
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 and six
months ended June 30, 1999 and 1998 (and the related percentage changes from
1998) is set forth below:
<TABLE>
<CAPTION>
Three Months Ended June 30
Percentage Percentage
MWH Increase Revenues (000's) Increase
1999 1998 (Decrease) 1999 1998 (Decrease)
<S> <C> <C> <C> <C> <C> <C>
Residential 212,248 212,368 (.1) $25,159 $24,428 3.0
Commercial 228,114 224,336 1.7 23,704 23,181 2.3
Industrial 97,612 98,530 (.9) 7,303 7,361 (.8)
Other retail 1,571 1,763 (10.9) 449 486 (7.6)
--------- -------- ------- -------
Total retail sales 539,545 536,997 .5 56,615 55,456 2.1
--------- -------- ------- -------
Resale sales:
Firm 432 451 (4.2) 37 18 105.6
Entitlement 81,892 50,744 61.4 5,216 5,279 (1.2)
Other 1,000,626 144,081 594.5 29,608 4,217 602.1
--------- -------- ------- -------
Total resale sales 1,082,950 195,276 454.6 34,861 9,514 266.4
--------- -------- ------- -------
Other revenues - - - 1,663 1,436 15.8
--------- -------- ------- -------
Total sales 1,622,495 732,273 121.6 $93,139 $66,406 40.3
========= ======== ======= =======
</TABLE>
<TABLE>
<CAPTION>
Six Months Ended June 30
Percentage Percentage
MWH Increase Revenues (000's) Increase
1999 1998 (Decrease) 1999 1998 (Decrease)
<S> <C> <S> <C> <C> <C> <C>
Residential 486,945 476,829 2.1 $63,852 $59,605 7.1
Commercial 463,434 452,768 2.4 54,028 50,643 6.7
Industrial 212,793 208,418 2.1 18,579 17,456 6.4
Other retail 3,109 3,565 (12.8) 888 969 (8.4)
--------- --------- -------- -------
Total retail sales 1,166,281 1,141,580 2.2 137,347 128,673 6.7
--------- --------- -------- -------
Resale sales:
Firm 1,346 1,125 19.6 79 37 113.5
Entitlement 181,260 135,756 33.5 9,947 10,263 (3.1)
Other 1,488,584 314,170 373.8 42,256 8,821 379.0
--------- --------- -------- --------
Total resale sales 1,671,190 451,051 270.5 52,282 19,121 173.4
--------- --------- -------- --------
Other revenues - - - 2,152 2,570 (16.3)
--------- --------- -------- --------
Total sales 2,837,471 1,592,631 78.2 $191,781 $150,364 27.5
========= ========= ======== ========
</TABLE>
Retail MWH sales for the second quarter of 1999 were relatively flat
compared to the second quarter of 1998, increasing only about .5%. The 2.1%
increase or $1.2 million in retail revenues was primarily the result of a 4.7%
temporary Vermont retail rate increase effective with service rendered January
1, 1999.
For the first half of 1999, retail MWH sales increased 2.2% compared to
the first half of 1998 reflecting a return to normal winter weather compared
to 1998.
Retail revenues increased $8.7 million or 6.7% for the first six months
of 1999 compared to last year. This variance is attributable to a $2.5
million impact of higher MWH sales and $6.2 million resulting from the 4.7%
temporary retail rate increase discussed above.
For the 1999 second quarter and first six months, entitlement MWH sales
increased 61.4% and 33.5% while related revenues decreased 1.2% and 3.1%
compared to the same periods last year. These variances result from the
Vermont Yankee extended refueling outage in 1998.
Other 1999 resale sales increased 856,545 MWH ($25.4 million) and
1,174,414 MWH ($33.4 million) for the second quarter and first six months,
respectively, primarily as a result of activity by the Company through its
alliance with Virginia Power in jointly supplying wholesale power in New
England.
Other revenues increased for the second quarter of 1999 primarily due to
the reversal of a provision for rate refunds of $.5 million as the result of
an April 7 1999 ruling by the Federal District Court discussed below.
Other revenues decreased for the first six months of 1999 primarily due
to lower revenues associated with transmission interconnection agreements and
pole attachment rentals.
Net Purchased Power and Production Fuel Costs
The net cost components of purchased power and production fuel costs for
the three and six months ended June 30, 1999 and 1998 are as follows (dollars
in thousands):
<TABLE>
<CAPTION>
Three Months Ended June 30
1999 1998
Units Amount Units Amount
<S> <C> <C> <C> <C>
Purchased and produced:
Capacity (MW) 749 $22,427 565 $26,674
Energy (MWH) 1,569,121 40,472 703,024 19,208
------- -------
Total purchased power costs 62,899 45,882
Production fuel (MWH) 90,202 730 71,537 394
------- -------
Total purchased power and
production fuel costs 63,629 46,276
Entitlement and other resale sales (MWH) 1,082,518 34,824 194,825 9,496
------- -------
Net purchased power and production
fuel costs $28,805 $36,780
======= =======
</TABLE>
<TABLE>
<CAPTION>
Six Months Ended June 30
1999 1998
Units Amount Units Amount
<S> <C> <C> <C> <C>
Purchased and produced:
Capacity (MW) 917 $44,911 567 $47,115
Energy (MWH) 2,744,620 68,023 1,539,300 38,473
------- -------
Total purchased power costs 112,934 85,588
Production fuel (MWH) 205,616 1,346 146,612 909
------- -------
Total purchased power and
production fuel costs 114,280 86,497
Less entitlement and
other resale sales (MWH) 1,669,844 52,203 449,926 19,084
------- -------
Net purchased power and production
fuel costs $62,077 $67,413
======= =======
</TABLE>
Net purchased power and production fuel costs decreased $8.0 million, or
21.7% for the second quarter of 1999 compared to the second quarter of 1998
primarily as the result of better performance at Millstone Unit No. 3 and
Vermont Yankee nuclear power plant. The 1999 second quarter also reflects the
positive impact of $1.8 million (pre-tax) as the result of disallowed Hydro-
Quebec power costs during the fourth quarter of 1998.
For the first half of 1999, net purchased power and production fuel costs
decreased $5.3 million or 7.9% compared to the first half of 1998 resulting
from better performance at Millstone Unit No. 3 and Vermont Yankee nuclear
power plant.
Energy purchases increased $21.3 million for the 1999 second quarter and
$29.6 million for the first six months of 1999. These increases primarily
relate to the Virginia Power Alliance and were offset by increases in other
resale sales described above.
In addition, the 1999 first half reflects the positive impact of $3.7
million (pre-tax) as the result of disallowed Hydro-Quebec power costs during
the fourth quarter of 1998. The 1998 first half reflects the positive impact
of reversing Connecticut Valley's fourth quarter 1997 charge of $5.5 million
pre-tax.
The Company owns and operates 20 hydroelectric generating units and two
gas turbines and one diesel peaking unit with a combined capability of 73.7
MW. The Company has equity ownership interests in four nuclear generating
companies: Vermont Yankee, Maine Yankee, Connecticut Yankee and Yankee Atomic.
In addition, the Company maintains joint-ownership interests in Joseph C.
McNeil, a 53 MW wood, gas and oil-fired unit; Wyman #4, a 619 MW oil fired
unit; and Millstone Unit #3, an 1149 MW nuclear unit.
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.
MERRIMACK UNIT #2
Until its termination on April 30, 1998, the Company purchased power and
energy from Merrimack Unit #2 pursuant to a contract dated July 16, 1966
entered into by and between Vermont Electric Power Company, Inc., or Velco and
Public Service Company of New Hampshire, or 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 that the portion of the
disputed charges allocable to the Company could be as much as $1.0 million on
a pre-tax basis.
NUCLEAR MATTERS
The Company maintains a 1.7303% joint-ownership interest in the Millstone
Unit No. 3 of the Millstone Nuclear Power Station and owns a 2% equity
interest in Connecticut Yankee. These two plants are operated by Northeast
Utilities, or NU. The Company also owns 2%, 3.5% and 31.3% equity interest in
Maine Yankee, Yankee Atomic and Vermont Yankee, respectively.
Millstone Unit No. 3
Millstone Unit No. 3 resumed operation in June 1998 after a lengthy
outage.
The Company remains actively involved with the other non-operating
minority joint-owners of Millstone Unit No. 3. This group is engaged in
various activities to monitor and evaluate NU and Northeast Utilities Service
Co.'s efforts relating to Millstone Unit No. 3. On August 7, 1997, the
Company and eight other non-operating owners of Millstone Unit No. 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 Millstone Unit No. 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.
Based on the most recent decommissioning estimate in 1997, the Company's
total share of the Millstone Unit No. 3 decommissioning costs at December 31,
1998 was $9.7 million. As of December 31, 1998, the Company has funded $3.2
million of these costs.
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.
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 $14.6 million, $9.4
million and $2.0 million, respectively, at June 30, 1999. These amounts are
subject to ongoing review and revisions and are reflected in the accompanying
balance sheet both as regulatory assets and nuclear decommissioning costs
(current and non-current). Although the estimated costs of decommissioning
are subject to change due to changing technologies and regulations, the
Company expects that the nuclear generating companies' liability for
decommissioning, including any future changes in the liability, will be
recovered in their rates over their operating or license lives.
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.
Vermont Yankee
The Design Basis Documentation project, or Project initiated by Vermont
Yankee during 1996 is expected to be completed by the end of 2000. The
Company's 35% share of the total cost for this Project is expected to be
between $5.5 million and $6.2 million. Such costs are being deferred by
Vermont Yankee and amortized over the remaining license life of the plant.
On February 25, 1999, the Board of Directors of Vermont Yankee granted an
exclusive right to AmerGen Energy Co. to conduct a 120-day period of due
diligence and negotiate a possible agreement to purchase the assets of Vermont
Yankee.
On July 16, 1999, the Board of Directors of Vermont Yankee delayed a
decision on whether to sell the nuclear unit to AmerGen Energy Co. until
August 2, 1999.
On August 2, 1999 Vermont Yankee received an unsolicited expression of
interest from Entergy Nuclear, Inc. to buy Vermont Yankee's nuclear power
plant. Vermont Yankee's owners, which includes the Company, intend to pursue
parallel negotiations with the two potential purchasers with the objective of
reaching a definitive agreement by October 1, 1999.
Cogeneration/Small Power Qualifying Facilities
A number of small power producers 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 which purchases and redistributes the power to all Vermont
utilities. For the three and six months ended June 30, 1999, the Company
received 47,595 MWH and 100,689 MWH, respectively, from these sources for
which the Company paid $5.2 million and $11.3 million, respectively.
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, Citizens' Utilities and all of Vermont's 15 municipal utilities, filed
a petition with the PSB requesting modification of the contracts between the
independent power producers and the utilities. 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, could
ultimately allow for the buy-out and buy-down of these contracts and reduce
ratepayers' committed power costs.
Production and Transmission
As a result of a settled transmission contract dispute with Hydro-Quebec,
production and transmission expenses decreased approximately $.6 million for
the first six months of 1999 compared to the first six months of 1998,
partially offset by higher nuclear fuel costs related to Millstone Unit No. 3.
Maintenance
The increase in maintenance expenses of approximately $.4 million for the
second quarter of 1999 results primarily from higher maintenance costs related
to Millstone Unit
No. 3.
The decrease in maintenance expenses of approximately $.6 million for the
first six months of 1999 results primarily from the severe ice storm in
January 1998 partially offset by increased maintenance costs related to
Millstone Unit No. 3.
Income Taxes
Federal and state income taxes fluctuate with the level of pre-tax
earnings. The increase in total income tax expense for the first quarter and
first six months of 1999 results primarily from an increase in pre-tax
earnings for the period.
Extraordinary Credit
The 1998 extraordinary credit net of taxes of approximately $.9 million
represents a reversal of a charge of a like amount taken in the fourth quarter
of 1997.
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 $32.9 million and $6.9 million for the first six months
ended June 30, 1999 and 1998, respectively. The increase is primarily due to
improved cash earnings, lower tax payments and the extended refueling outage
at the Vermont Yankee Nuclear Power Plant during 1998.
The Company ended the first six months of 1999 with cash and cash
equivalents of $19.3 million, an increase of $9.2 million from the beginning
of the year. The increase in cash for the first six months of 1999 was the
result of $32.9 million provided by operating activities, offset by $8.9
million used for investing activities and $14.8 million used for financing
activities.
Operating Activities - Net income, depreciation and deferred income taxes
and investment tax credits provided $23.0 million. About $9.9 million of cash
was provided by working capital and other operating activities.
Investing Activities - Construction and plant expenditures consumed
approximately $5.8 million, while $3.1 million was used for C&LM programs and
non-utility investments.
Financing Activities - Dividends paid on common stock were $5.0 million
while preferred dividends were $.5 million and reduction in capital lease
obligations required $.5 million. Reduction in short-term debt was $8.8
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% in accordance with
Securities and Exchange Commission Rule 144A. 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 bonds have not been registered under the Securities Act of 1933 and may
not be offered or sold in the United States absent registration under such Act
or applicable exemption from the registration requirements.
The Company has an aggregate of $16.9 million of letters of credit with
termination dates that have been extended to May 31, 2000 with renewal options
through November 5, 2002. In addition, the Company has a $12.0 million
accounts receivable facility which matures in November 1999.
On March 12, 1999, Connecticut Valley was notified by Citizens Bank of
New Hampshire, or Bank that it would exercise appropriate remedies in
connection with the violation of financial covenants associated with the $3.75
million loan agreement with the Bank 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 February 2, 1999, Standard & Poor's Corporation, or Standard & Poor's
lowered its corporate credit rating on the Company to triple-'B'-minus from
triple-'B', the senior secured rating to triple-'B'-plus from single-'A'-minus,
and the preferred stock rating to double-'B'-plus from triple-'B'-minus.
However, on February 17, 1999, Standard & Poor's rating on the Company's
preferred stock was automatically reduced to double-'B'- in response to a
global policy change in the way Standard & Poor's rates preferred stock.
In addition, the ratings were also placed on Credit Watch with negative
implications.
Standard & Poor's stated "the CreditWatch listing reflects the
potentially adverse impact of pending legal and regulatory decisions that
could seriously weaken the Company's credit profile. The downgrades reflect
increased business risk and weakened financial measures as a result of recent
regulatory decisions in Vermont and New Hampshire and an adverse ruling by the
United States First Circuit Court of Appeals."
Standard & Poor's also said "Resolution of the CreditWatch listing will
depend on the outcome of the pending Federal Energy Regulatory Commission case
and other legal proceedings at State and Federal levels, which could be
resolved in 1999. Adequate rate relief and successful mitigation of high
power costs through contract renegotiations or other methods are essential to
stabilizing the ratings."
On July 16, 1999, Standard & Poor's assigned its triple-'B'- minus rating
to the Company's proposed $75.0 million second mortgage bonds. Concurrently,
the bonds were placed on credit watch 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 February 17, 1999, Duff & Phelps Credit Rating Co., or 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 recent
unfavorable ruling by the United States Court of Appeals relating to
Connecticut Valley, the Company's wholly owned New Hampshire subsidiary.
Duff & Phelps stated "recent negative rulings by the PSB regarding
purchased power costs and the high level of uncertainty with public policy
toward electric utilities in Vermont adds risk to the Company's financial
profile going forward."
On July 16, 1999 Duff & Phelps lowered the preferred stock rating to
'BB+' (Double-B-plus) from 'BBB-' (Triple-B-minus) to reflect the new $75.0
issuance of second mortgage bonds. Duff & Phelps credit ratings remain at
'BBB' (Triple-B) for first mortgage bonds.
Current credit ratings of the Company's securities by Duff & Phelps and
Standard & Poor's are as follows:
Duff & Standard
Phelps & Poor's
Corporate Credit Rating N/A BBB-
First Mortgage Bonds BBB BBB+
Second Mortgage Bonds BBB- BBB-
Preferred Stock BB+ BB
On November 12, 1998, Catamount, replaced its $8.0 million credit
facility with a $25.0 million revolving credit facility expiring November 11,
2002 which provides for up to $25.0 million in revolving credit loans and
letters of credit. 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 and aggregated
letters of credit of $11.0 million in support of construction and equity
commitments for its Gauley River Power project.
Financial obligations of the Company's non-regulated 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 assure you that any 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
through 2016 as a party to a power contract with Hydro-Quebec entered into
through the VJO, a consortium of Vermont utilities which includes the Company,
Green Mountain Power, Citizens Utilities, Rochester Electric Light & Power and
the Vermont Public Power Supply authority representing municipalities and a
cooperative in Vermont. The Company's obligation is approximately 46% of the
total contract, or approximately $1.0 billion over the next 17 years based on
current power market forecasts. The VJO participation contract under which the
VJO resells Hydro-Quebec power to the Vermont purchasing utilities, including
the Company, contains "step up" provisions providing that if any purchasing
utility defaults on its purchase obligations, the other participants will
assume responsibility for the defaulting party's share on a pro rata basis.
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. The VJO believes Hydro-Quebec has
been and remains unable to make available capacity with the degree of firmness
required by the VJO Power Contract. That review 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. Hearings are scheduled for this fall with
final decisions expected in the early part of 2000.
Diversification
Catamount Resources Corporation was formed for the purpose of holding the
Company's subsidiaries that invest in non-regulated business opportunities.
Catamount Energy Corporation, or Catamount, a subsidiary of Catamount
Resources Corporation, invests in energy generation projects in the United
States and Great Britain. Through its wholly-owned subsidiaries, Catamount
has interests in six operating independent power projects located in Glenns
Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; Thetford,
England; and Hopewell, Virginia. In addition, Catamount has interests in a
project under construction in Summersville, West Virginia and a project under
development in Fort Dunlop, England. Catamount's after-tax earnings were $.3
million and $.7 million for the second quarter 1999 and 1998, respectively and
$.9 million and $1.3 million for the first six months of 1999 and 1998,
respectively.
SmartEnergy Services Inc., or SmartEnergy, also a subsidiary of Catamount
Resources Corporation invests in unregulated energy and service related
businesses. SmartEnergy also owns 70% of Home Service Solutions, or HSS, which
provides home and small business maintenance and repair services. HSS is
currently operating in five U.S. cities as part of a pilot program with Sam's
Clubs, a division of Wal-Mart. SmartEnergy incurred losses of $.5 million for
both the second quarter 1999 and 1998 and losses of $.6 million and $.9
million for the first six months of 1999 and 1998, respectively.
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: 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 Vermont Supreme
Court, or 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 Vermont Joint
Owners, or VJO, Power Contract presently before the Vermont Supreme Court. 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 Vermont Supreme Court. As a result of the 4.7% rate increase
agreement, during the fourth quarter of 1998, the Company recorded a pre-tax
loss of $7.4 million for disallowed purchased power costs, representing the
Company's estimated under-recovery of power costs under the VJO Power Contract
for calendar year 1999.
This temporary $7.4 million disallowance was calculated using comparable
methodology to that used by the PSB in the Green Mountain Power rate case on
February 28, 1998. In that case, the PSB found Green Mountain Power'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 Green Mountain Power's current costs should not be imposed
on Green Mountain Power's customers and were disallowed. Green Mountain Power
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.
Assuming an unfavorable Vermont Supreme Court ruling and depending on the
methodology used to determine the amount of any permanent disallowance could
be more or less than the $7.4 million temporary disallowance. However, if the
Company receives an unfavorable ruling from the Vermont Supreme Court 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 $205.0 million of power costs over the
life of the contract, including $11.5 million in 2000, $11.6 million in 2001,
$11.7 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 $205.0 million (pre-tax). Such an outcome could
jeopardize the ability of the Company to continue as a going concern.
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. At the same time, the Company also filed
a request to eliminate the then current differential between the rates charged
customers in the summer and the rates charged customers in the winter and
price electricity the same year-round. The change would be revenue-neutral
within classes of customers and overall. Over time, customers would see a
leveling off of rates so they would pay the same per kilowatt-hour during the
winter and summer months.
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 Department of Public Service,
or 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 recently argued its
position before the Vermont Supreme Court. The Vermont Supreme Court has not
rendered a decision, but a decision by the end of 1999 is possible.
On February 28, 1998 the PSB issued an Order in a Green Mountain Power
rate case. That Order found Green Mountain Power's decision to lock-in the
Hydro-Quebec VJO contract in 1991 imprudent and further found that the
contract was not used and useful. As such, the PSB concluded that a large
portion of the contract's current costs should not be imposed on consumers and
were disallowed. Green Mountain Power appealed this rate order to the VSC.
The Company is one of the participants in the Hydro-Quebec VJO contract. 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 Green Mountain Power 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 demand side management, or DSM 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.
New Hampshire: Connecticut Valley Electric Company Inc. or Connecticut
Valley's retail rate tariffs, approved by the New Hampshire Public Utilities
Commission, or NHPUC, contain a Fuel Adjustment Clause, or FAC, and a
Purchased Power Cost Adjustment, or 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
overcollections 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 3 to the Consolidated Financial Statements for
additional information.
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 New
Hampshire Public Utilities Commission (NHPUC) issued an Order allowing
Connecticut Valley to implement the proposed FAC rate of $.008 per kWh and the
proposed PPCA rate of $.01000 per kWh rate on a temporary basis, effective on
all bills rendered on or after January 1, 1999. In addition, the NHPUC
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, or Court, Order, should it be overturned or modified.
See Electric Industry Restructuring-New Hampshire for additional information
related to the Court Order.
Proposed Formation of Holding Company
In order to further prepare the Company for deregulation of the electric
utility industry in Vermont, on July 24, 1998, the Company filed a petition
with the PSB for permission to create a holding company that would have as
direct subsidiaries the Company and the unregulated 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.
Year 2000 Information Systems Modifications
The Company's information systems could be affected by the date change in
Year 2000 because most software application and operational programs will not
properly recognize calendar dates beginning in the Year 2000. If not
corrected, many computer applications could fail or create erroneous results.
In order to meet current and future business needs the Company retained
outside consultants to make its customer service applications Year 2000
compliant. In addition, the Company utilized both internal and external
resources to make other applications, including its desk top applications,
Year 2000 ready. Inventory, assessment and remediation testing and
implementation activities are complete. The Company achieved compliance with
year 2000 requirements for all of its financial and operating systems on June
30, 1999.
The Company's operations would be adversely affected if a date-related
system failure occurred with one of its major power suppliers, such as Hydro-
Quebec or Vermont Yankee, or Velco, the company responsible for transmission
in Vermont. Velco indicates it is Year 2000 ready. Other delivery systems
outside the state could, in the event of a date-related system failure, cause
additional power supply interruptions. The Company has requested written
reports from its power supply vendors regarding each Company's status relative
to Year 2000 compliance and based on responses to date, these power supply
vendors have indicated that they are either currently compliant or expect to
be compliant by the third quarter of 1999.
The Company has also requested compliance information from other major
vendors and suppliers. While this process is not yet complete, based upon
responses to date, many of those major vendors and suppliers have indicated
that they will be Year 2000 compliant in a timely manner. However, there can
be no guarantee that third parties' noncompliance and their failure to
remediate Year 2000 issues would not have a material adverse effect on the
Company.
Failures of the Company's principal power and transmission suppliers to
remedy Year 2000 compliance issues, could have a material adverse effect on
the Company should non-compliance result in interruptions of power supply and
transmission.
The Company is part of the Northeast grid contingency plan that would go
into effect immediately which would provide electricity to its customers on a
priority basis in the event of power outages. The Company also has
contingency plans developed in the event of the failure of its transmission,
generation, distribution, metering, telecommunications, information and public
communications systems.
The Company believes it will incur approximately $3.8 million of costs
associated with making the necessary modifications to its centralized and
non-centralized computer systems. As of June 30, 1999, approximately
$3.6 million of those costs have been incurred.
During the first quarter of 1998, the Company requested an Accounting
Order from the PSB to defer these operating and maintenance costs. On
August 31, 1998, the PSB issued an Accounting Order authorizing the Company to
defer a portion of these costs and amortize them over a five-year period
beginning January 1, 2000. Per PSB Order dated December 11, 1998, the Company
is authorized to recover these costs through future regulatory proceedings.
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. 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 is considering restructuring
proposals; and(3) Senate Bill 62 of the Vermont Senate, which calls for retail
competition.
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 of
Vermont 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 its report were:
- The bankruptcy of Vermont electric utilities should not be viewed as an
appropriate means to reduce Vermont utilities' above-market 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 our 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 a formal proceeding in 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 would define one or more acceptable courses for reform. All Vermont
utilities were made a party to that 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.
As of this time, the PSB has yet to act on any proposal or recommendation
made concerning the disposition of the matters in Docket No. 6140. As a
companion proceeding to its investigation in Docket No. 6140, 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 first consider the principles, authority and proposals for reform
of Vermont's electric power supply. This includes 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., or VEPP, the PSB's
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, this investigation will be closed by
the PSB.
Vermont Senate Bill 62
On April 3, 1997, Senate Bill 62, or S.62, an act relating to electric
industry restructuring, was passed by the Vermont Senate. Pursuant to S.62,
electric utility customers would have been entitled to purchase electricity in
a competitive market place. Incumbent investor-owned electric utilities,
including the Company, would have been required to separate their regulated
distribution and transmission operations from the competitive generation and
retail operations. S.62 provided for the recovery of a portion of an investor-
owned utility's "above market costs" which became stranded on account of the
introduction of competition within their service area. When considering the
recovery of such amounts, S.62 would have required the PSB to weigh the goal of
sharing net prudently incurred, discretionary above-market costs "evenly"
between utilities and customers against other goals including preserving the
continuing financial integrity of the existing utility and respecting the just
interests of investors.
The Company believes that the unmodified provisions of S.62 would not
have met the criteria for continuing application of SFAS No. 71. S.62 also
created an incentive for us to take steps to close the Vermont Yankee nuclear
power station by conditioning the recovery of certain plant-related stranded
costs on the decision of its owners to cease operations in 1998, unless the
PSB agreed to allow the plant to run for up to two more refuelings to avoid
power shortages or for other public interest reasons.
To become law, S.62 also needed to pass the Vermont House of
Representatives and be signed by the Governor of the State of Vermont. Since
the 1998 Legislative session adjourned in April 1998 and S.62 was not passed
by the House and signed by the Governor of Vermont, the bill did not become
law and therefore died upon adjournment.
Instead of considering S.62, the Vermont House of Representatives
convened a special committee to study matters relating to the reform of
Vermont's electric utility system in the summer of 1997. That committee issued
a report and proposed legislation that would have provided for performance-
based ratemaking but explicitly rejected retail choice. However, neither the
House of Representatives nor the Vermont Senate acted on these reforms and the
bill died upon adjournment. Therefore, at this time, it cannot be determined
whether future restructuring legislation will be enacted in the current
Biennium of the Vermont legislature.
The first session of the 1999-2000 Biennium of the Vermont legislature
adjourned on May 15, 1999 without reaching a consensus on electric utility
restructuring. Several measures were considered by various committees of the
House and the Senate, including securitization, authorization of retail
choice, establishment of a legislative veto over any restructuring agreement
reached between the PSB and the utilities, various mandated levels of rate
reductions for customers paying stranded costs, and capturing for customers
any or a portion of the gain from the sale of a utility's transmission and
distribution assets.
The Company expects the second session of the Biennium, which convenes on
January 4, 2000, will be very active on restructuring issues. However, it
cannot be predicted at this time whether restructuring legislation will be
enacted in this Biennium.
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 a report that
the Company and Green Mountain Power 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 Hydro-Quebec and the Vermont purchasing agent's
contracts with small power producers which together represent nearly 41%
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 interest in the Vermont
Yankee nuclear generating plant. Efforts to sell the Vermont Yankee
plant and possibly purchase a portion of the power from the plant are
already under way.
- Cost-cutting: implementing cost-cutting measures to reduce cash flow
requirements while maintaining safety and reliability standards.
- Holding company: establishing a holding company to help the Company
better organize its business.
- Industry consolidation: evaluating possible consolidation 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 system-wide energy-efficiency services
for electric customers.
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. See "Rate
Establishment" below. 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.
Retail Choice
The Company intends to file a petition with the PSB to establish retail
access for its customers. The petition will:
- confirm the Company's consent to providing its retail customers their
choice of power suppliers;
- seek a PSB order relieving the Company of its obligation to supply
capacity and energy to consumers; and
- establish the Company as the exclusive electric distribution provider
within its service territory.
The Company will also propose tariffs to establish open access and
customer choice. All of these proposals would result in the Company giving up
current exclusive rights to serve present customers' electricity requirements,
except for distribution services, and allow competitive electricity sales for
its electric customers in Vermont, as part of a global settlement with the
regulators.
Renegotiation of Power Purchase Agreements
The Company intends to reduce its future cost of power through the buy-
out or buy-down of these power purchase agreements with Hydro-Quebec and the
Vermont purchasing agent's contracts with independent power producers. The
power purchase agreements accounted for approximately 38% of the Company's
retail MWH needs in 1998. If the Company successfully renegotiates these
agreements, and appropriate regulatory approvals are obtained, the Company
intends to seek to finance the payments made to power suppliers with
securities issued in the capital markets. This aspect of the Restructuring
Plan would effectively create an unsecured on-balance sheet liability, and
possibly an off-balance sheet liability for Vermont's independent power
producers contracts, for the repayment of debt incurred to fund buy-downs or
buy-outs for the above-market costs of the power purchase agreements. The
Company believes that a successful re-negotiation would result in improved
operating cash flow that would be adequate to service the obligations related
to the purchased agreements and fund ongoing operations. Participants in the
VJO, the Company included, are now negotiating the terms under which the
agreements obligating (i) the VJO to buy power from Hydro-Quebec and (ii) VJO
participants to buy their respective percentage commitments from the VJO can
be restructured. There can be no assurances, however, that the Company will be
successful in renegotiating these contracts or in completing the related
financing.
On August 3, 1999, the Company, Green Mountain Power, Citizens' Utilities
and all of Vermont's 15 municipal utilities, filed a petition with the PSB
requesting modification of the contracts between the independent power
producers and the utilities. 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, should ultimately allow for the buy-
out and buy-down of these contracts and reduce ratepayers' committed power
costs.
Disposition of Certain Assets
The Company is evaluating wholly owned and jointly owned generating
sources to determine whether they should be sold, operated or shut down. On
February 25, 1999, the Board of Directors of Vermont Yankee granted an
exclusive right to AmerGen Energy Co. to conduct due diligence and negotiate a
possible agreement to purchase the assets of Vermont Yankee.
On August 2, 1999 Vermont Yankee received an unsolicited expression of
interest from Entergy Nuclear, Inc. to buy Vermont Yankee's nuclear power
plant. Vermont Yankee's owners, which includes the Company, intend to pursue
parallel negotiations with the two potential purchasers with the objective of
reaching a definitive agreement by October 1, 1999.
Creation of an Energy-Efficiency Utility
On April 30, 1999, the Company entered into a Memorandum of
Understanding, or MOU, with the DPS, for the creation of an energy-efficiency
utility to provide state-wide demand-side management services. Subsequently,
other Vermont utilities, as well as consumer interest groups, have endorsed
the proposal. The MOU was filed with the PSB on April 30, 1999 for approval in
Docket No. 5980 which was opened by the PSB to investigate the DPS's proposed
Statewide Energy Efficiency Plan.
If approved by the PSB, the MOU would resolve all issues now outstanding
in Docket No. 5980 including the governance structure for the energy
efficiency utility, the design of the energy efficiency utility programs and
services, and the energy efficiency utility budgets. The MOU also resolves all
claims based on alleged actions or failures to act prior to January 1, 2000
that we failed to satisfy our demand-side management obligations to customers
under Vermont law and regulations. The PSB is currently considering the
approval of the MOU which is expected during the third quarter of 1999. If
approved by the PSB, the new energy efficiency delivery system would be in
place beginning in the year 2000 and would replace services now provided to
customers by the Company. In May 1999, the legislature approved, and in June
the Governor of Vermont signed, legislation supportive of the MOU.
Consolidation
The Company has signed individual confidentiality and cooperation
agreements with Green Mountain Power, Citizens Utilities and Washington
Electric Cooperative to permit an exchange of information to evaluate the
possibility of consolidating Vermont utility operations. There have been no
material developments as a result of these agreements.
Cost-Cutting Opportunities
The Company has been actively pursuing cost-cutting opportunities to
improve its financial performance. The Company estimates that its number of
employees will have been reduced by 32% from 1993 through 2000.
Rate Establishment
If the realization of other elements of the Company's Restructuring Plan
begins, the Company will file petitions with the PSB for the establishment of
rates that would provide for revenues in amounts sufficient to support the
financings necessary to restructure its power supply portfolio in the above
manner. It is essential that the PSB permits the Company to recover in rates
an annual amount sufficient to cover costs, including those incurred in
connection with various components of the Restructuring Plan.
New Hampshire
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 17, 1997, the City of Claremont, New Hampshire (Claremont),
filed with the NHPUC a petition for a reduction in Connecticut Valley's
electric rates. Claremont based its request on the NHPUC's earlier finding
that Connecticut Valley's failure to terminate its wholesale power contract
with the Company as ordered in the NHPUC Stranded Cost Order of February 28,
1997 was imprudent. Claremont alleged that if Connecticut Valley had given
written notice of termination to the Company in 1996 when legislation to
restructure the electric industry was enacted in New Hampshire, Connecticut
Valley's obligation to purchase power from the Company would have terminated
as of January 1, 1998.
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
overcollections from 1996. Connecticut Valley objected to the NHPUC's notice
of intent to consolidate Claremont's petition into the FAC and PPCA docket,
stating that Claremont's complaint should be heard as part of the NHPUC
restructuring docket. Over Connecticut Valley's objection at the hearing on
December 17, 1997, the NHPUC consolidated Claremont's petition with
Connecticut Valley's FAC and PPCA proceeding.
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 cancelled
because of the Court's June 5, 1998 Order, discussed below.
On June 5, 1998, the Court issued an Order which denied 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 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 increase the proposed FAC rate
of $.008 per KWH and the proposed PPCA rate of $.01000 per KWH rate 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 above.
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 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.
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. Company management, however,
continues to believe that the NHPUC's actions are illegal and unconstitutional
and will present its arguments in the appropriate forum.
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. A briefing schedule has been established that extends
into early October 1999.
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. No further action has
been scheduled by the Court.
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,
1999, is approximately $48.0 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 later this year, and the FERC will act on
the judge's recommendations sometime thereafter.
If the Company is unable to obtain an order authorizing the recovery of
costs in connection with the June 1997 FERC filing, the Company would be
required to recognize a pre-tax loss under this contract totaling
approximately $60.0 million on a pre-tax basis. The Company would also be
required to write-off approximately $4.0 million (pre-tax)in regulatory assets
associated with its wholesale business. The cash flow shortfall from the
revenues would be approximately $6.0 million (pre-tax) annually. 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 $48.0 million (pre-tax).
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 and 1998 charges and reversals of the 1997 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, 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 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 and attract new customers
or the margins that will be realized on retail sales of electricity.
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
included in its 1998 Annual Report on Form 10-K, 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 $60.7 million on a pre-tax basis as
of June 30, 1999. 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, 1998, 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.
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 cases 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 Millstone Unit No.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 Millstone
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.
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, 3 and 4
None.
Item 5. Other Information.
In May 1999, the City Council of the City of Claremont New Hampshire
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 will require that the City 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 without the
municipality as the public interest may require. The Company would thereafter
have sixty days to reply to the City's inquiry. If there is no agreement
between the Company and the City, Claremont may proceed to condemn the
Company's facilities with proceedings before the New Hampshire Public Utilities
Commission as provided for in Chapter 38 and the FERC as provided for in its
Rule 35.26 (18CFR Chapter 1). The matter is scheduled to be presented to the
citizens of Claremont for a vote in November 1999. The Company intends to
vigorously pursue its rights.
Item 6. Exhibits and Reports on Form 8-K.
(a) List of Exhibits
4. Instruments defining the rights of security holders,
including indentures
4-56.4 Fourth Amendment to Credit Agreement Dated as of
May 25, 1999.
10. Material Contracts
A 10.90 Performance Share Incentive Plan dated effective
January 1, 1999.
A - compensation related plan, contract or arrangement
27. Financial Data Schedule
(b) Item 5. There were no reports on Form 8-K for the quarter
ended June 30, 1999.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
(Registrant)
By Francis J. Boyle
Francis J. Boyle, Senior Vice President, Principal
Financial Officer and Treasurer
By James M. Pennington
James M. Pennington, Vice President, Controller
and Principal Accounting Officer
Dated August 12, 1999
<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>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 316448
<OTHER-PROPERTY-AND-INVEST> 64834
<TOTAL-CURRENT-ASSETS> 77309
<TOTAL-DEFERRED-CHARGES> 65510
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 524101
<COMMON> 66506
<CAPITAL-SURPLUS-PAID-IN> 45329
<RETAINED-EARNINGS> 77436
<TOTAL-COMMON-STOCKHOLDERS-EQ> 188906
17000
8054
<LONG-TERM-DEBT-NET> 90066
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 3023
1000
<CAPITAL-LEASE-OBLIGATIONS> 15601
<LEASES-CURRENT> 1094
<OTHER-ITEMS-CAPITAL-AND-LIAB> 199357
<TOT-CAPITALIZATION-AND-LIAB> 524101
<GROSS-OPERATING-REVENUE> 191781
<INCOME-TAX-EXPENSE> 7795
<OTHER-OPERATING-EXPENSES> 168267
<TOTAL-OPERATING-EXPENSES> 176062
<OPERATING-INCOME-LOSS> 15719
<OTHER-INCOME-NET> 2533
<INCOME-BEFORE-INTEREST-EXPEN> 18252
<TOTAL-INTEREST-EXPENSE> 5106
<NET-INCOME> 13146
931
<EARNINGS-AVAILABLE-FOR-COMM> 12215
<COMMON-STOCK-DIVIDENDS> 2527
<TOTAL-INTEREST-ON-BONDS> 3111
<CASH-FLOW-OPERATIONS> 32899
<EPS-BASIC> 1.07
<EPS-DILUTED> 1.07
</TABLE>
Exhibit 4-56.4
FOURTH AMENDMENT
TO CREDIT AGREEMENT
FOURTH AMENDMENT, dated as of May 25, 1999 (this
"Amendment"), to the Credit Agreement referred to below by
and among CENTRAL VERMONT PUBLIC SERVICE
CORPORATION, a Vermont corporation ("Borrower"), each
of the lenders thatis a signatory to the Credit Agreement or which,
pursuant to Section 10.6 thereof shall become a "Lender" thereunder (the
"Lenders"), FLEET NATIONAL BANK, as syndication agent (the
"Syndication Agent"), and TORONTO DOMINION (TEXAS), INC., as
agent for the Lenders hereunder (the "Agent"; Lenders,
Syndication Agent and Agent are sometimes collectively
referred to herein as the "Lending Group").
W I T N E S S E T H
WHEREAS, the Borrower and the Lending Group are
parties to that certain Credit Agreement, dated as of
November 5, 1997 (as heretofore amended, supplemented or
otherwise modified, the "Credit Agreement"); and
WHEREAS, the Borrower and the Lending Group have
agreed to amend the Credit Agreement in the manner, and on
the terms and conditions, provided for herein.
NOW THEREFORE, in consideration of the premises
and for other good and valuable consideration, the receipt,
adequacy and sufficiency of which are hereby acknowledged,
the Borrower and the Lending Group hereby agree as follows:
1. Definitions. Capitalized terms not otherwise
defined herein shall have the meanings ascribed to them in
the Credit Agreement, as amended hereby (the "Amended Credit
Agreement").
2. Amendments to the Credit Agreement. The Credit
Agreement shall be amended as of the Amendment Effective
Date (as hereinafter defined) as follows:
(a) Section 1.1 of the Credit Agreement is
amended by deleting in its entirety the table appearing in
the definition of "Applicable Margin" and inserting in lieu
thereof the following new table:
"Debt Rating Applicable Margin
BB (or lower) 1.775%
BB+ 1.525%
BBB- 1.325%
BBB 1.250%
BBB+ 1.210%
A- (or higher) 1.175%"
(b) Section 1.1 of the Credit Agreement is
further amended by deleting the definition of "Maturity
Date" in its entirety and inserting in lieu thereof the
following new definition:
"Maturity Date" shall mean May 31, 2000,
unless extended as provided in Section 2.6(b), in which case
the Maturity Date shall mean May 30, 2001, May 30, 2002 or
November 5, 2002, as the case may be."
(c) Section 1.1 of the Credit Agreement is
further amended by inserting therein the following new
definitions in the appropriate alphabetical order:
"ABR Margin" shall mean, for each ABR Loan,
the applicable rate per annum set forth below based on the
respective Debt Rating:
Debt Rating ABR Margin
BB (or lower) 0.775%
BB+ 0.525%
BBB- 0.325%
BBB 0.250%
BBB+ 0.210%
A- (or higher) 0.175%
"Capital Expenditures" shall mean, with
respect to any Person, all expenditures (by the expenditure
of cash or the incurrence of Indebtedness) by such Person
during any measuring period for any fixed assets or
improvements or for replacements, substitutions or additions
thereto, that have a useful life of more than one year and
that are required to be capitalized under GAAP.
"Interest Coverage Ratio" shall mean the
ratio of (a) the sum of the following items related to the
Borrower's utility operations (excluding all non-cash
charges and credits related to FAS 5 and FAS 71, but
including all power costs when paid which are related to FAS
5 charges): net operating income, income taxes, amortization
and depreciation, less Capital Expenditures, to (b)
Borrower's net utility interest expense (whether cash or
noncash)."
(d) Section 2.3 of the Credit Agreement is
amended by deleting in its entirety the table appearing
therein and inserting in lieu thereof the following new
table:
"Debt Rating Facility Fee
BB (or lower) 0.725%
BB+ 0.650%
BBB- 0.550%
BBB 0.500%
BBB+ 0.475%
A- (or higher) 0.450%"
(e) Section 2.4(a) of the Credit Agreement is
amended and restated in its entirety to read as follows:
"(a) Subject to the provisions of Sections
2.3(c) and 2.4(c), each ABR Loan shall bear interest at a
rate per annum (computed on the basis of the actual number
of days elapsed over a year of 365 or 366 days, as the case
may be) equal to the ABR plus the ABR Margin."
(f) Section 2.6(b) of the Credit Agreement is
amended and restated in its entirety to read as follows:
"(b) So long as (i) no Default or Event of
Default has occurred and is continuing and (ii) there has
been no material adverse change in the business or financial
condition of the Borrower since June 2, 1999, then on each
of June 1, 2000, May 31, 2001 and May 31, 2002, the Borrower
may, at its option, upon not less than ninety (90) nor more
than one hundred eighty (180) days' prior written notice to
the Agent and subject to the approval of all of the Lenders,
extend the Maturity Date for an additional one-year period,
or if shorter until November 5, 2002."
(g) Section 2.9A of the Credit Agreement is
amended and restated in its entirety to read as follows:
"(a) If the Borrower issues First Mortgage
Bonds at any time after October 5, 1998, no later than the
Business Day following the date of receipt of the proceeds
thereof, the Borrower shall prepay the Loans in an amount
equal to all such proceeds, net of commissions and other
reasonable costs paid in connection therewith. In addition,
each Lender's Commitment shall be reduced permanently by an
amount equal to its Commitment Percentage multiplied by the
amount of such net proceeds.
(b) If at any time the commitment of
BankBoston, N.A. under the Receivables Purchase Agreement,
dated as of November 29, 1988, between the Borrower and
BankBoston, N.A. (as successor to The First National Bank),
as the same may be amended, supplemented or otherwise
modified from time to time, exceeds $17,000,000, each
Lender's Commitment shall be reduced permanently by an
amount equal to its Commitment Percentage multiplied by the
amount of such excess. If at any time the outstanding
balance of the Loans exceeds the aggregate Commitments,
Borrower shall immediately repay the Loans to the extent
required to eliminate such excess.
(c) Any prepayments made by the Borrower
pursuant to this Section 2.9A above shall be applied as
follows: first, to Fees, reimbursable expenses of the Agent
and any indemnity amounts to which any Secured Party is
entitled then due and payable by the Borrower pursuant to
any of the Loan Documents; second, to all interest then due
and payable on any outstanding Loans; and third, to the
principal balance of any outstanding Loans; provided that
outstanding ABR Loans shall be prepaid in full prior to the
prepayment of any outstanding Eurodollar Loans.
(d) Notwithstanding the foregoing
provisions of this Section 2.9A, if at any time the
mandatory prepayment of Loans required above would result in
the Borrower incurring breakage costs under Section 2.15 as
a result of Eurodollar Loans or Auction Advances being
prepaid other than on the last day of an Interest Period
applicable thereto (the "Affected Loans"), then the Borrower
may in its sole discretion initially deposit a portion (up
to 100%) of the amounts that otherwise would have been paid
in respect of the Affected Loans with the Agent (which
deposit, after giving effect to interest to be earned on
such deposit prior to the last day of the relevant Interest
Periods, must be equal in an amount to the amount of
Affected Loans not immediately prepaid) to be held as
security for the obligations of the Borrower hereunder
pursuant to a cash collateral agreement to be entered into
in form and substance reasonably satisfactory to the Agent,
with such cash collateral to be directly applied upon the
first occurrence (or occurrences) thereafter of the last day
of an Interest Period applicable to the relevant Loans that
are Eurodollar Loans or Auction Advances (or such earlier
date or dates as shall be requested by the Borrower), to
repay an aggregate principal amount of such Loans equal to
the Affected Loan not initially repaid pursuant to this
sentence. Notwithstanding anything to the contrary
contained in the immediately preceding sentence, all amounts
deposited as cash collateral pursuant to the immediately
preceding sentence shall be held for the sole benefit of the
Lenders whose Loans would have been immediately repaid with
the amounts deposited and upon the taking of any action by
the Agent or the Lenders pursuant to the remedial provisions
of Section 8.1, any amounts held as cash collateral pursuant
to this Section 2.9A(d) shall, subject to the requirements
of applicable law, be immediately applied to the relevant
Loans. Following repayment of the relevant Loans, any
remaining cash collateral will be returned to the Borrower."
(h) A new Section to the Credit Agreement is
hereby inserted immediately following Section 7.6, which
Section shall read as follows:
"SECTION 7.7 Interest Coverage Ratio. Permit
the Interest Coverage Ratio at the end of each calendar
quarter for the preceding four calendar quarters then ended
to be less than 1.50:1.00."
(i) Schedules 1 and 2 to the Credit Agreement are
amended by deleting such schedules in their entirety and
inserting in lieu thereof new schedules in the forms
attached hereto as Schedules 1 and 2, respectively.
3. Representations and Warranties. To induce the
Lending Group to enter into this Amendment, the Borrower
hereby represents and warrants that:
(a) The execution, delivery and performance by the
Borrower of this Amendment and the amended notes referred to
in Section 5(c) hereof (the "Amended Notes") and the
performance of the Amended Credit Agreement hereby have been
duly authorized by all necessary corporate and shareholder
action and (i) do not violate any Requirement of Law, (ii)
do not breach or result in an event of default under, or
otherwise violate the terms of, any indenture (including,
without limitation, the Indenture) or material agreement to
which the Borrower is a party or by which it or its property
is bound, (iii) will not result in or require the creation
of any Lien upon or with respect to any of its properties,
and (iv) do not require any consent or approval of any
creditor of the Borrower (including, without limitation, the
Indenture Trustee and the holders of the First Mortgage
Bonds).
(b) Each of this Amendment and the Amended Notes
has been duly executed and delivered by the Borrower.
(c) Each of this Amendment, the Amended Credit
Agreement and the Amended Notes are legal, valid and binding
obligations of the Borrower, enforceable against the
Borrower in accordance with their respective terms, subject
to (i) the effect of applicable bankruptcy, insolvency,
reorganization or moratorium or other similar laws affecting
the enforcement of creditors' rights generally, and (ii) the
application of general principles of equity (regardless of
whether considered in a proceeding in equity or at law).
(d) No Governmental Approvals are required for the
due execution, delivery and performance by the Borrower of
this Amendment, the Amended Credit Agreement and the Amended
Notes other than the approval or consent of the Vermont
Public Service Board and the approval of or waiver by the
Connecticut Department of Public Utility Control.
(e) There is no pending, or to the best of the
Borrower's knowledge, threatened action or proceeding
against the Borrower before any court, governmental agency
or arbitrator, which if adversely determined, could
reasonably be expected to materially adversely affect the
financial condition or results of operations of the Borrower
or that could otherwise materially adversely affect the
Borrower's ability to perform its obligations under any of
this Amendment, the Amended Credit Agreement or the Amended
Notes other than as described in the Borrower's Annual
Report on Form 10-K for the fiscal year ended December 31,
1998 and Form 10-Q for the fiscal quarter ended March 31,
1999.
(f) No Default or Event of Default has occurred
and is continuing, both before and after giving effect to
the execution and delivery of this Amendment and the Amended
Notes.
(g) The representations and warranties of the
Borrower contained in the Credit Agreement and each other
Loan Document shall be true and correct on and as of the
Amendment Effective Date with the same effect as if such
representations and warranties had been made on and as of
such date, except that any such representation or warranty
which is expressly made only as of a specified date shall be
true only as of such date.
4. No Other Amendments. Except as expressly
amended herein, each of the Credit Agreement and the other
Loan Documents shall be unmodified and shall continue to be
in full force and effect in accordance with its terms.
5. Effectiveness. This Amendment shall become
effective at such time on or after June 2, 1999 (the
"Amendment Effective Date") that each of the following
conditions have been satisfied in full in the judgment of
the Agent:
(a) Amendment. The Agent shall have received six
(6) original copies of this Amendment duly executed and
delivered by the Borrower, the Agent, the Syndication Agent
and the Lenders.
(b) Notes. Each Lender shall have received an
original Second Amended and Restated Revolving Loan Note,
payable to such Lender, duly executed by the Borrower,
substantially in the form of Schedule 2 to the Amended
Credit Agreement and duly completed in accordance with the
Amended Credit Agreement.
(c) Legal Opinions. The Agent shall have received
such legal opinions addressed to each of the Secured
Creditors as the Agent may reasonably request relating to
this Amendment and the Amended Credit Agreement, which
opinions shall be in form and substance, and from counsel,
reasonably acceptable to the Agent and its counsel.
(d) Board Resolutions and Incumbency Certificates
of Borrower. The Agent shall have received in form and
substance satisfactory to it a certificate of the Secretary
or an Assistant Secretary of Borrower certifying (i) the
resolutions adopted by the Borrower's Board of Directors
approving this Amendment and the transactions contemplated
hereby and (ii) the names and true signatures of the
authorized officers of Borrower.
(e) Articles of Incorporation; By-Laws and Good
Standing Certificates. The Agent shall have received in
form and substance satisfactory to it each of the following
documents:
(i) the certificate of incorporation of the
Borrower as in effect on the Amendment Effective Date,
certified by the Secretary of State or other appropriate
authority of the State of Vermont as of a recent date, and
the by-laws of the Borrower as in effect on the Amendment
Effective Date, certified by the Secretary, Assistant
Secretary or other appropriate officer of the Borrower; and
(ii) a good standing certificate for the
Borrower from the Secretary of State of the State of Vermont
as of a recent date.
(f) Approval. The Agent shall have received
evidence satisfactory to it and its counsel that the
Borrower has received the approval or consent of the Vermont
Public Service Board and the approval of or waiver by any
other state regulatory body with jurisdiction, in each case
required for (A) the increase in the interest rates and the
facility fee payable with respect to the Loans, (B) the
extension of the Maturity Date and (C) the other amendments
to the Credit Agreement, in each case effected hereby.
(g) Restructuring Fee. The Agent shall have
received, for the ratable benefit of the Lenders, a
restructuring fee in the amount of $100,000, which fee shall
be fully earned and nonrefundable as of the Amendment
Effective Date.
(h) Agency Fee. The Agent shall have received the
fee required to be paid on the Amendment Effective Date
pursuant to the Fee Letter, dated the date hereof, between
the Agent and the Borrower.
(i) Representations and Warranties. The
representations and warranties of the Borrower contained in
this Amendment shall be true and correct on and as of the
Amendment Effective Date.
6. Secured Obligations. After giving effect to
the amendments contemplated herein, the Secured Obligations
shall continue to be secured by the Mortgage and the
Security Agreement.
7. GOVERNING LAW. THIS AMENDMENT SHALL BE
GOVERNED BY, AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF
THE STATE OF NEW YORK.
8. Counterparts. This Amendment may be executed
by the parties hereto on any number of separate counterparts
and all of said counterparts taken together shall be deemed
to constitute one and the same instrument.
(SIGNATURE PAGE FOLLOWS)
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused
this Amendment to be duly executed and delivered as of the
day and year first above written.
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
By: /s/ Francis J. Boyle
Name: Francis J. Boyle
Title: Senior Vice President, Chief Financial Officer and Treasurer
TORONTO DOMINION (TEXAS), INC., as Agent
By:
Name:
Title:
TORONTO DOMINION (NEW YORK), INC.
By:
Name:
Title:
BANKBOSTON, N.A.
By:
Name:
Title:
FLEET NATIONAL BANK, as Syndication Agent and Lender
By:
Name:
Title:
CITIZENS BANK NEW HAMPSHIRE
By:
Name:
Title:
<TABLE>
Schedule 1
COMMITMENTS OF THE LENDERS
<CAPTION>
Lender Address Commitment Commitment Percentage
<S> <C> <C> <C>
Toronto Dominion 909 Fannin, $10,676,471 26.69%
(New York), Inc. Houston, TX
77010
BankBoston, N.A. 100 Federal St. 7,117,647 17.79%
Boston, MA
02110
Citizens Bank 20 West Park St. 9,750,000 24.38%
New Hampshire Lebanon, NH
03766
Fleet National One Federal St. 12,455,882 31.14%
Bank Boston, MA
02110
Total $40,000,000 100%
</TABLE>
<PAGE>
Exhibit A
Schedule 2 to CREDIT AGREEMENT
FORM OF SECOND AMENDED AND RESTATED REVOLVING LOAN NOTE
November 5, 1997
$XX,000,000 New York, New York
For value received, CENTRAL VERMONT PUBLIC
SERVICE CORPORATION, a Vermont corporation (the "Borrower"),
hereby unconditionally promises to pay on the Revolving Loan
Maturity Date to the order of [each Lender] (the "Lender"),
in lawful money of the United States of America and in
immediately available funds, a principal sum equal to
_____________________ Dollars ($XX,000,000.00) or, if less,
the aggregate unpaid principal amount of all Revolving Loans
made by the Lender to the Borrower under and pursuant to the
Credit Agreement dated as of November 5, 1997 (as amended,
supplemented or otherwise modified from time to time, the
"Credit Agreement"), among the Borrower, the lenders from
time to time party thereto, including the Lender, and
Toronto Dominion (Texas), Inc., as Agent (together with its
successors in such capacity, the "Agent"). The Borrower
further agrees to pay interest in like money on the unpaid
principal amount hereof from time to time outstanding at the
rates and on the dates determined in accordance with the
Credit Agreement. All payments of principal and interest
with respect to this Note shall be made by the Borrower at
the office of the Agent at 909 Fannin Street, Suite 1700,
Houston, Texas 77010, or such other office as shall be from
time to time specified by the Agent to the Borrower.
The holder of this Note shall, and is hereby
irrevocably authorized by the Borrower to, endorse on the
Loan Schedule attached hereto and forming a part hereof (and
on separate continuations of such Loan Schedule which shall
be attached hereto and form a part hereof), or otherwise to
record on the Lender's internal records, appropriate
notations evidencing the date, Type and amount of each
Revolving Loan made under and pursuant to the Credit
Agreement, each continuation thereof, each conversion of all
or a portion thereof to another Type, the date and amount of
each payment or prepayment of principal of this Note which
is received by the Lender and, in the case of Eurodollar
Loans, the length of each Interest Period with respect
thereto, which recordation shall constitute prima facie
evidence of the accuracy of the information so recorded;
provided that failure by the Lender to make any such
notations or any error therein shall not affect any of the
Borrower's obligations in respect of this Note or obligate
the Borrower to pay any amounts in excess of the amounts
otherwise payable by the Borrower hereunder.
This Note is one of the Revolving Loan Notes
referred to in the Credit Agreement and any holder hereof is
entitled to all of the rights, remedies, benefits and
privileges provided for in the Credit Agreement, which,
among other things, contains provisions for the repayment
hereof and also for optional and mandatory prepayments
hereof under certain conditions. Upon the occurrence of any
one or more of the Events of Default specified in the Credit
Agreement, all amounts then remaining unpaid on this Note
shall become, or may be declared to be, immediately due and
payable, all as provided in the Credit Agreement.
The Borrower waives presentment, demand, protest,
notice of protest, notice of nonpayment or dishonor and all
other demands and notices in connection with the delivery,
acceptance, performance, default or enforcement of this Note
(other than such of the foregoing as are expressly required
by the terms of the Credit Agreement) and, to the fullest
extent permitted by applicable law, assents to any extension
or postponement of the time of payment or any other
indulgence, to any substitutions, exchange or release of
collateral and to the addition or release of any other party
or person, primarily or secondarily liable.
Terms defined in the Credit Agreement are used
herein as therein defined.
Payment of this Note is secured by the Security
Agreement and the Mortgage.
This Note amends and restates as of June 2, 1999
that certain Amended and Restated Revolving Loan Note dated
November 5, 1997 in the original principal amount of
[$______________] made by the Borrower in favor of the
Lender (the "Prior Note") and this Note is in substitution
and exchange for (but not in payment of) the Prior Note.
THIS NOTE SHALL BE GOVERNED BY, AND CONSTRUED IN
ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK DETERMINED
WITHOUT REFERENCE TO PRINCIPLES OF CONFLICTS OF LAW.
<PAGE>
IN WITNESS WHEREOF, the Borrower has caused this
Revolving Loan Note to be duly executed and delivered under
seal by its officer thereunto duly authorized as of the date
hereof.
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
By:
Name:
Title:
<PAGE>
<TABLE>
LOAN SCHEDULE TO REVOLVING LOAN NOTE
Loans, Conversions and Payments of ABR Loans
<CAPTION>
<S> <C> <C> <C> <C> <C> C>
Amount Amount Amount of Amount of Unpaid Notation
Date of ABR of ABR Loans Eurodollar Principal Made
Loans Principal Converted Loans Balance By
Repaid to Converted of ABR
Eurodollar to ABR Loans
Loans Loans
</TABLE>
<TABLE>
LOAN SCHEDULE TO REVOLVING LOAN NOTE
Loans, Conversions and Payments of Eurodollar Loans
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C>
Amount Amount Amount Interest Amount Unpaid Notation
of of of Period of ABR Principal Made
Date Eurodollar Principal Eurodollar for Loans Balance By
Loans Repaid Loans Eurodollar Converted of
Converted Loans to Eurodollar
to ABR Eurodollar Loans
Loans Loans
</TABLE>
Exhibit A10.90
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PERFORMANCE SHARE INCENTIVE PLAN
Effective January 1, 1999
May 1999
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PERFORMANCE SHARE INCENTIVE PLAN
TABLE OF CONTENTS
Section
ARTICLE I PURPOSE
ARTICLE II DEFINITIONS
"Account" 2.1
"Award" 2.2
"Board" 2.3
"Change of Control" 2.4
"Code" 2.5
"Committee" 2.6
"Common Stock" or "Stock" 2.7
"Comparison Group" 2.8
"Dividend Equivalent" 2.9
"Effective Date" 2.10
"Employer" 2.11
"Exchange Act" 2.12
"Fair Market Value" 2.13
"Participant" 2.14
"Performance Cycle" 2.15
"PeRS" 2.16
"Plan" 2.17
"Pro Rata Portion" 2.18
"Stock Unit" 2.19
"Target PeRS" 2.20
"Termination of Employment" 2.21
"Total Shareholder Return" 2.22
ARTICLE III DETERMINATION OF PERFORMANCE SHARES
3.1
Maximum Shares Granted 3.2
Adjustment of and Changes in Stock 3.3
ARTICLE IV PAYMENT OF GRANTS
Performance Awards 4.1
Accounts 4.2
Payment of Account 4.3
ARTICLE V TERMINATION OF EMPLOYMENT
Termination Prior to Completion of
Performance Cycle 5.1
Change of Control 5.2
ARTICLE VI ADMINISTRATION
Committee 6.1
Amendment and Termination 6.2
ARTICLE VII GENERAL PROVISIONS
Payments to Minors and Incompetents 7.1
No Contract 7.2
Use of Masculine and Feminine;
Singular and Plural 7.3
Non-Alienation of Benefits 7.4
Income Tax Withholding 7.5
Continuation of Plan 7.6
Governing Law 7.7
Captions 7.8
Severability 7.9
<PAGE>
ARTICLE I
PURPOSE
Effective January 1, 1999, Central Vermont Public Service
Corporation (the "Employer") has established The Central
Vermont Public Service Corporation Performance Share Plan (the
"Plan") in order to strengthen the ability of the Employer to
attract and retain talented executives and to promote the
long-term growth and profitability of the Employer by linking
a significant element of executives' compensation opportunity
to the performance of the Employer (relative to an established
peer group) over an extended period of time.
ARTICLE II
DEFINITIONS
2.1 "Account" means the bookkeeping account established for
the Participant under Section 4.2.
2.2 "Award" means any payment or settlement in respect of a
grant of Common Stock or cash or any combination thereof in
accordance with Section 4.1.
2.3 "Board" means the Board of Directors of Central Vermont
Public Service Corporation.
2.4 "Change of Control" means (a), (b) or (c) below:
(a) The acquisition, directly or indirectly, of securities of
the Employer representing 20% or more of the combined voting
power of the Employer's then outstanding securities by any
third person including a "Group" as that term is used in
Section 13(d)(3) of the Exchange Act; or
(b) A change in the membership of the Board 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
Employer, if immediately subsequent to the acquisition of the
Employer's voting securities by such third person:
(i) such third person shall be a "public utility holding
company" within the meaning of the Public Utility Trading
Company Act of 1935 (the "1935 Act"), whether or not exempt
from registration thereunder, or
(ii) the Employer shall be in danger of losing its exemption
under the 1935 Act or shall otherwise be required to register
under the 1935 Act.
2.5 "Code" means the Internal Revenue Code of 1986, as amended
from time to time, and pertinent regulations issued thereunder.
Reference to any section of the Code shall include any successor
provision thereto.
2.6 "Committee" means the Compensation Committee appointed by
the Board to administer this Plan. The Committee shall be
comprised of at least 3 members who qualify as "non-employee
directors" within the meaning of Rule 16B-3 promulgated under
the Exchange Act.
2.7 "Common Stock" or "Stock" means the common stock of the
Employer.
2.8 "Comparison Group" means the peer group of companies
designated by the Committee as the Comparison Group relative
to a given Performance Cycle, as described in Section 3.1(c)
2.9 "Dividend Equivalent" means credits in respect of each
PeRS (as defined in section 2.16) or other Stock Unit
representing an amount equal to the dividends or distributions
declared and paid on a share of Common Stock.
2.10 "Effective Date" means January 1, 1999, the effective
date of this Plan.
2.11 "Employer" means Central Vermont Public Service
Corporation, its subsidiaries and affiliates, and its
successor or successors.
2.12 "Exchange Act" means the Securities Exchange Act of
1934, as amended and in effect from time to time, including all
rules and regulations promulgated thereunder.
2.13 "Fair Market Value" means the average of the high and low
quoted selling price for a share of Common Stock of the
Company on the applicable date as quoted on the New York Stock
Exchange ("NYSE") in the Eastern Edition of the Wall Street
Journal or in a similarly readily available public source on
such date. If such date shall not be a business day, then the
next preceding day which shall be a business day, or if no
sale takes place, then the average of the bid and asked prices
on such date.
2.14 "Participant" means an employee of the Employer who is
selected by the Board to participate in this Plan.
2.15 "Performance Cycle" means the period over which PeRS
designated in respect of the Performance Cycle potentially may
be earned. Performance Cycles will be three-year periods
extending from January 1 of the initial year through December
31 of the third year in the Performance Cycle. Performance
Cycles generally will begin each year, and therefore will
overlap with one another.
2.16 "PeRS" means Stock Units which are potentially earnable
by a Participant hereunder upon achievement of specific levels
of Total Shareholder Return as compared to a Comparison Group
or other performance goals. The term is an acronym for
"performance-based restricted Stock Units".
2.17 "Plan" means the Central Vermont Public Service
Corporation Performance Share Incentive Plan, as set forth
herein, as may be amended from time to time. Shares for this
plan were approved by shareholders on May 6, 1997 as the
Restricted Stock Plan for Non-Employee Directors and Key
Employees.
2.18 "Pro Rata Portion" means a portion of a specified number
of PeRS relating to a given Performance Cycle determined by
multiplying such number of PeRS by a fraction the numerator of
which is the number of calendar days from the beginning of the
Performance Cycle to the date of Participant's Termination of
Employment and the denominator of which is the number of
calendar days in the Performance Cycle (subject to adjustment
under Section 3.3).
2.19 "Stock Unit" is a bookkeeping unit which represents a
right to receive one share of Common Stock upon settlement,
together with a right to accrual of additional Stock Units as
a result of Dividend Equivalents, subject to the terms and
conditions of this Plan. Stock Units are arbitrary accounting
measures created and used solely for purposes of this Plan,
and do not represent ownership rights in the Employer, shares
of Common Stock, or any asset of the Employer.
2.20 "Target PeRS" means a number of PeRS designated as a
target number that may be earned by a Participant in respect
to a given Performance Cycle plus the number of PeRS resulting
directly or indirectly from Dividend Equivalents on the
originally designated number of Target PeRS.
2.21 "Termination of Employment" means the Participant's
termination of employment with the Employer.
2.22 "Total Shareholder Return" means the amount, expressed as
a percentage, of market price appreciation or depreciation of
a share of common stock plus dividends on a share of Common
Stock or on the common stock of a company in the Comparison
Group (in both cases excluding extraordinary dividends),
assuming dividend reinvestment at the dividend payment date,
for the specified 3-year period.
ARTICLE III
DETERMINATION OF PERFORMANCE SHARES
3.1(a)Designation of PeRS and Related Terms. Not later than 90
days after the beginning of a Performance Cycle, the Committee
shall: (i) select employees to participate in the Performance
Cycle; (ii) designate, for each such employee Participant, the
Target PeRS number such Participant shall have the opportunity
to earn in such Performance Cycle; (iii) specify the duration
of the Performance Cycle; and (iv) specify a table, grid or
formula that sets forth the amount of PeRS that will be earned
corresponding to the percentile rank of the Company's average
Total Shareholder Return for the three years ending on the
last day of the Performance Cycle as compared to the
unweighted average Total Shareholder Return of the Comparison
Group for the three years ending on the last day of the
Performance Cycle. The Committee may, in its discretion,
reduce or eliminate the amount of payment with respect to an
Award of PeRS to a Participant, notwithstanding the
achievement of a specified performance condition.
(b)The provisions of 3.1(a)notwithstanding, at any time during
a Performance Cycle, the Committee may select a new employee
or a newly promoted employee who was not currently
participating in the Performance Cycle to participate in the
Performance Cycle and designate, for any such employee
Participant, the number of PeRS or additional PeRS such
Participant shall have the opportunity to earn in such
Performance Cycle; provided, however, that such designation
must be effective at least six months before the stated end
date of the Performance Cycle. In determining the number of
Target PeRS to be designated under this paragraph (b), the
Committee may take into account the portion of the Performance
Cycle already elapsed, the performance achieved during such
elapsed portion of the Performance Cycle, and such other
considerations as the Committee may deem relevant. The
Committee shall also determine whether any calculation of the
Pro Rata Portion for such Participant shall be adjusted to
include or exclude periods prior to the Participant's
employment in the numerator or denominator used in calculating
such amount.
(c)Comparison Group. The Comparison Group for each Performance
Cycle shall be designated by the Committee, provided that, if
the Committee does not designate a new Comparison Group for
any Performance Cycle, the Comparison Group shall be that most
recently designated by the Committee. The Comparison Group for
the Performance Cycle beginning in 1999 shall be as set forth
in Exhibit B to this Plan. In the event a merger, acquisition,
or other extraordinary corporate event affects a company
included in the Comparison Group, and if as a result in the
Committee's judgment such event causes Total Shareholder
Return for such company not to be comparable with periods
prior to the event or otherwise necessitates a change or
adjustment to ensure continued comparability, the Committee
shall make such adjustments, including substituting another
company in place of the affected company, in order to maintain
the comparability of results of the Comparison Group.
(d)Determination of Number of Earned PeRS. Not later than 120
days after the end of each Performance Cycle, the Committee
shall determine the extent to which the performance goals for
the earning of PeRS were achieved during such Performance
Cycle and the number of PeRS (or, the "Award") earned by each
Participant with respect to such Performance Cycle. The
Committee shall make written determinations that the
performance goals and any other material terms relating to the
earning of PeRS were in fact satisfied.
3.2 Maximum Shares Granted. Subject to adjustment as provided
in 3.3 below, the maximum number of shares of Common Stock
which may be granted to all Participants under this Plan
during the term of the Plan shall be limited to 70,000 in
accordance with the maximum number of shares authorized by
shareholders in the Restricted Stock Plan for Non-Employee
Directors and Key Employees approved by shareholders on May 6,
1997. The shares of Common Stock which may be issued under
the Plan may be authorized and unissued shares or issued
shares which have been reacquired by the Employer. No
fractional share of the Common Stock shall be issued under the
Plan. Awards of fractional shares of the Common Stock, if
any, shall be settled in cash.
3.3 Adjustment of and Changes in Stock. In the event of any
change in the outstanding shares of Common Stock by reason of
any stock dividend or split, recapitalization, merger,
consolidation, spinoff, combination or exchange of shares or
other similar corporate transaction, or any distributions to
common shareholders other than regular cash dividends, the
Committee may make such substitution or adjustment, if any, as
it deems to be equitable, as to the number or kind of shares
of Common Stock, PeRS, and/or other securities issued,
reserved or granted for any purpose under this Plan.
ARTICLE IV
PAYMENT OF GRANTS
4.1 Performance Awards. Subject to the applicable provisions
of Article III, each Participant shall be entitled to receive
an Award of Common Stock in an amount equal to the aggregate
Fair Market Value of the PeRS earned in respect of a
Performance Cycle. Participants shall be immediately vested in
such Award as of the date it is granted.
4.2 Accounts. The Committee shall maintain a bookkeeping
Account for each Participant reflecting the number of PeRS
credited to the Participant hereunder. The Account may include
subaccounts or other designations as the Committee may deem
appropriate.
4.3 Payment of Account. Payment of an Account may be made in
shares of Common Stock, in cash equal to the Fair Market Value
of the shares on the date as of which payment is made, or in
any combination of Common Stock and cash, and at such time or
times as the Committee, in its discretion, shall determine.
The intent is to grant the payment in shares of common stock
subject to sections 3.3 and 7.5 of this plan.
The Committee may, whether at the time of grant or at any time
thereafter prior to payment or settlement, permit (subject to
such conditions as the Committee may from time to time
establish in order to provide for matters such as the
effective deferral of taxation) a Participant to elect to
defer receipt of all or any portion of any payment of cash or
shares of Common Stock that would otherwise be due to such
Participant in payment or settlement of any Award under the
Plan. If any such deferral is elected by the Participant with
the permission of the Committee, the Committee shall establish
rules and procedures for such payment deferrals. The Committee
may provide for the payment or crediting of interest, at such
rate or rates as it shall in its discretion deem appropriate,
on such deferred amounts credited in cash and the payment or
crediting of Dividend Equivalents in respect of deferred
amounts credited in Common Stock Units. Deferred amounts may
be paid in a lump sum or in installments in the manner and to
the extent permitted, and in accordance with rules and
procedures established, by the Committee.
ARTICLE V
TERMINATION OF EMPLOYMENT
5.1 Termination Prior to Completion of Performance Cycle.
(a)Upon a Participant's Termination of Employment with the
Employer prior to completion of a Performance Cycle all
unearned PeRS relating to such Performance Cycle shall cease
to be earnable and shall be cancelled, and Participant shall
have no further rights or opportunities hereunder.
(b)Disability, Death, or Retirement. If Termination of
Employment is due to the death or the Disability or Retirement
(as such terms are defined under the provisions of The Pension
Plan of Central Vermont Public Service Corporation and Its
Subsidiaries, i.e., the "Pension Plan") of the Participant,
the Participant or his beneficiary (as designated for purposes
of the Pension Plan) shall be deemed to have earned and shall
be entitled to receive settlement of the Pro Rata Portion of
the PeRS relating to the Performance Cycles in effect at the
date of termination, at the time and to the extent such PeRS
would otherwise have been earned and settled, in accordance
with Article IV if the individual had not terminated until
after the close of the Performance Cycles. Notwithstanding the
foregoing, in the event that such Termination of Employment is
effective as of the last day of a calendar year, the
Participant shall only be entitled to earn the aforementioned
PeRS, as otherwise determined in this paragraph (b), upon
approval of the Board.
If the Participant has timely filed an irrevocable election to
defer settlement of PeRS following a termination of
employment, such earned PeRS shall be settled in accordance
with such deferral election. Other PeRS relating to the
Performance Cycles in effect at the date of such termination
will cease to be earnable and will be cancelled.
5.2 Upon a Participant's Termination of Employment that occurs
as a result of a Termination Event (as such term is defined in
The Central Vermont Public Service Corporation Officers'
Supplemental Retirement and Deferred Compensation Plan)
following a Change in Control, the Participant shall be deemed
to have earned and shall be entitled to receive, in accordance
with the applicable provisions of the Plan, the Pro Rata
Portion of the PeRS relating to Performance Cycles in effect
as of the Change in Control. Other PeRS relating to the
Performance Cycles will cease to be earnable and will be
cancelled.
ARTICLE VI
ADMINISTRATION
6.1 Committee. This Plan shall be administered by the Board
through the Compensation Committee. The Committee shall have
full discretion to interpret and administer the Plan and its
decision in any matter involving the interpretation and
application of this Plan shall be final and binding on all
parties. The Committee may delegate to one or more of its
members or to any Officer or Officers of the Company such
administrative duties under the Plan as the Committee may
deem advisable.
6.2 Amendment and Termination. The Compensation Committee
reserves the right to amend, modify, suspend or terminate
this Plan in whole or in part at any time by action of the
Board. However, no such amendment may alter the maximum
number of shares specified in Section 3.2 without
shareholder approval.
ARTICLE VII
GENERAL PROVISIONS
7.1 Payments to Minors and Incompetents. If any
Participant, spouse or beneficiary entitled to receive any
benefits hereunder is a minor or is deemed by the Committee
or is adjudged to be legally incapable of giving valid
receipt and discharge for such benefits, they will be paid
to such person or institution as the Committee may designate
or to the duly appointed guardian. Such payment shall, to
the extent made, be deemed a complete discharge of any such
payment under the Plan.
7.2 No Contract. This Plan shall not be deemed a contract
of employment with any Participant, nor shall any provision
hereof affect the right of the Employer to terminate a
Participant's employment.
7.3 Use of Masculine and Feminine; Singular and Plural.
Wherever used in this Plan, the masculine gender will
include the feminine gender and the singular will include
the plural, unless the context indicates otherwise.
7.4 Non-Alienation of Benefits. No amount payable to, or
held under the Plan for the account of, any Participant,
spouse or beneficiary shall be subject in any manner to
anticipation, alienation, sale, transfer, assignment,
pledge, encumbrance, or charge, and any attempt to so
anticipate, alienate, sell, transfer, assign, pledge,
encumber, or charge the same shall be void; nor shall any
amount payable to, or held under the Plan for the account
of, any Participant be in any manner liable for such
Participant's debts, contracts, liabilities, engagements, or
torts, or be subject to any legal process to levy upon or
attach.
7.5 Income Tax Withholding. As a condition to the delivery
of any Shares, the Committee may require that the
Participant, at the time of such payment of shares, pay to
the Company an amount to satisfy any applicable tax
withholding obligation or such greater amount of withholding
as the Committee shall determine from time to time, or the
Committee may take such other action as it may deem
necessary to satisfy any such withholding obligations. The
Committee, in its sole discretion, may permit or require
Participant to satisfy all or a part of the tax withholding
obligations incident to the payment of shares by having the
Company withhold a portion of the Shares that would
otherwise be issuable to the Participant. Such Shares shall
be valued based on their Fair Market Value on the date the
tax withholding is required to be made. Any such Share
withholding with respect to a Participant subject to Section
16(a) of the Exchange Act shall be subject to such
limitations as the Committee may impose to comply with the
requirements of Section 16 of the Exchange Act.
7.6 Continuation of Plan. In the event of a Change of
Control, this Plan shall remain in full force and effect as
an obligation of the Employer or its successors in interest.
7.7 Governing Law. The provisions of the Plan shall be
interpreted, construed, and administered in accordance with
the referenced provisions of the Code and with the laws of
the State of Vermont.
7.8 Captions. The captions contained in the Plan are
inserted only as a matter of convenience and for reference
and in no way define, limit, enlarge, or describe the scope
or intent of the Plan nor in any way affect the construction
of any provision of the Plan.
7.9 Severability. If any provision of the Plan is held
invalid or unenforceable, its invalidity or unenforceability
will not affect any other provision of the Plan, and the
Plan will be construed and enforced as if such provision had
not been included.
<PAGE>
IN WITNESS WHEREOF, the Employer has caused this instrument
to be executed by its duly authorized officer as of the
day of , 1999.
CENTRAL VERMONT PUBLIC
SERVICE CORPORATION
By: /s/ Frederic H. Bertrand
Attest:
(Corporate Seal)
<PAGE>
Exhibit A
PeRS Earned for Total Shareholder Return Performance
for Performance Cycle Commencing on January 1, 1999
Three-Year Total
Shareholder Return -
Employer Percentile Rank Multiple of
vs. Comparison Group Target PeRS Earned
90th percentile or higher 2.0
75th percentile 1.5
50th percentile 1.0
40th percentile 0.5
Below 40th percentile 0.0
The resulting three-year Total Shareholder Return determined
for this Plan shall be rounded up to nearest percentile
specified above. The multiple of Target PeRS earned between
each of the respective percentiles specified above shall be
determined by linear interpolation.
<PAGE>
Exhibit B
Comparison Group for Performance Cycle
Commencing January 1, 1999
Publicly-Traded Utility Peer Group Companies
SIC Codes: 4911 Electric Services and 4931 Electric Services
& Other Service Combos
COMPANY NAME
Allegheny Energy
Alliant
Ameren
American Electric Power
Baltimore Gas & Electric
BEC Energy
Black Hills
Carolina Power & Light
Central & South West
CIL
Cinergy
Citizens Utilities
Cleco
CMP Group
CMS Energy
Commonwealth Energy System
Conectiv
Consolidated Edison
Dominion Resources
DPL
DQE
DTE Energy
Duke Energy
Eastern Utilities Associate
Edison International
El Paso Electric
Empire District Electric
Energy East
Entergy
Firstenergy
Florida Progress
FPL Group
GPU
Hawaiian Electric Industries
Illinova
Ipalco Enterprises
Kansas City Power & Light
LG&E Energy
Madison Gas & Electric
Maine Public Service
Midamerican Energy Hldg.
Minnesota Power & Light
Montana Power
Nevada Power
New England Electric System
Niagara Mohawk Power
Nipsco Industries
Northern Utilities
Northern States Power/Mn
Northwestern
OGE Energy
Orange & Rockland Utilities
Otter Tail Power
Pacific Corporation
Peco Energy
PG&E
Pinnacle West Capital
Potomac Electric Power
PP&L Resources
Public Service of New Mexico
Public Service Enterprises
Puget Sound Energy
Reliant Energy
Rochester Gas & Electric
Scana
Sierra Pacific Resources
SIG Corp.
Southern
St. Joseph Light & Power
TECO Energy
Texas Utilities
TNP Enterprises
Unicom
Unisource Energy
United Illuminating
Upper Peninsula Energy
Utilicorp United
Unitil
Washington Water Power
Western Resources
Wisconsin Energy
WPS Resources
