SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
Form 10-Q
x QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 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 April 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 three months ended March 31, 1999 and 1998 3
Consolidated Balance Sheet as of March 31, 1999 and
December 31, 1998 4
Consolidated Statement of Cash Flows for the three
months ended March 31, 1999 and 1998 5
Notes to Consolidated Financial Statements 6-14
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 15-34
PART II. OTHER INFORMATION 35-36
SIGNATURE 37
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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
March 31
1999 1998
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Operating Revenues $98,642 $83,958
Operating Expenses
Operation
Purchased power 50,035 39,706
Production and transmission 5,000 5,588
Other operation 12,039 11,434
Maintenance 2,884 3,852
Depreciation 4,185 4,227
Other taxes, principally property taxes 3,087 3,040
Taxes on income 7,557 5,432
------- -------
Total operating expenses 84,787 73,279
------- -------
Operating Income 13,855 10,679
------- -------
Other Income and Deductions
Equity in earnings of affiliates 640 732
Allowance for equity funds during construction 10 17
Other income, net 1,059 578
Provision for income taxes (245) 10
Total other income and deductions, net 1,464 1,337
------- -------
Total Operating and Other Income 15,319 12,016
------- -------
Interest Expense
Interest on long-term debt 2,093 2,531
Other interest 503 103
Allowance for borrowed funds during construction (7) (9)
------- -------
Total interest expense, net 2,589 2,625
------- -------
Net Income Before Extraordinary Credit 12,730 9,391
Extraordinary Credit Net of Taxes - 873
------- -------
Net Income 12,730 10,264
Retained Earnings at Beginning of Period 67,748 75,841
------- -------
80,478 86,105
Cash Dividends Declared
Preferred stock 465 486
Common stock - 6
------- -------
Total dividends declared 465 492
------- -------
Retained Earnings at End of Period $80,013 $85,613
======= =======
Earnings Available For Common Stock $12,265 $ 9,778
Average Shares of Common Stock Outstanding 11,461,131 11,423,951
Basic and Diluted Share of Common Stock:
Earnings before extraordinary credit $1.07 $.78
Extraordinary credit - .08
----- ----
Earnings Per Basic and Diluted Share of Common Stock $1.07 $.86
----- ----
Dividends Paid Per Share of Common Stock $ .22 $.22
The accompanying notes are an integral part of these consolidated financial
statements.
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED BALANCE SHEET
(Dollars in thousands)
March 31 December 31
1999 1998
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Assets
Utility Plant, at original cost $469,883 $469,204
Less accumulated depreciation 164,526 160,666
-------- --------
305,357 308,538
Construction work in progress 11,272 10,461
Nuclear fuel, net 1,417 948
-------- --------
Net utility plant 318,046 319,947
-------- --------
Investments and Other Assets
Investments in affiliates, at equity 25,957 26,142
Non-utility investments 37,620 35,896
Non-utility property, less accumulated depreciation 2,806 2,920
-------- --------
Total investments and other assets 66,383 64,958
-------- --------
Current Assets
Cash and cash equivalents 30,703 10,051
Special deposits 426 424
Accounts receivable, less allowance for uncollectible
accounts ($2,206 in 1999 and $2,242 in 1998) 29,078 29,224
Unbilled revenues 14,454 18,677
Materials and supplies, at average cost 3,616 3,746
Prepayments 2,041 1,881
Other current assets 6,100 9,768
-------- --------
Total current assets 86,418 73,771
-------- --------
Regulatory Assets 63,745 66,719
-------- --------
Other Deferred Charges 5,047 4,887
-------- --------
Total Assets $539,639 $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 45,324 45,318
Accumulated other comprehensive income (365) (365)
Treasury stock (324,717 shares, at cost) (4,234) (4,234)
Retained earnings 80,013 67,748
-------- --------
Total common stock equity 191,453 179,182
Preferred and preference stock 8,054 8,054
Preferred stock with sinking fund requirements 17,000 18,000
Long-term debt 90,071 90,077
Capital lease obligations 15,871 16,141
-------- --------
Total capitalization 322,449 311,454
-------- --------
Current Liabilities
Short-term debt 37,000 37,000
Current portion of long-term debt and preferred stock 7,773 6,773
Accounts payable 6,680 11,589
Accounts payable - affiliates 10,269 11,784
Accrued income taxes 7,974 2,975
Dividends declared 465 2,521
Nuclear decommissioning costs 4,820 4,820
Disallowed purchased power costs 5,520 7,361
Other current liabilities 20,325 17,403
-------- --------
Total current liabilities 100,826 102,226
-------- --------
Deferred Credits
Deferred income taxes 47,767 47,581
Deferred investment tax credits 6,733 6,831
Nuclear decommissioning costs 22,185 23,239
Other deferred credits 39,679 38,951
-------- --------
Total deferred credits 116,364 116,602
-------- --------
Total Capitalization and Liabilities $539,639 $530,282
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)
(Unaudited)
Three Months Ended
March 31
1999 1998
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Cash Flows Provided (Used) By
Operating Activities
Net income $12,730 $10,264
Adjustments to reconcile net income to net cash
provided by operating activities
Equity in earnings of affiliates (745) (732)
Dividends received from affiliates 928 618
Equity in earnings of non-utility investments (1,372) (1,659)
Distribution of earnings from non-utility
investments 815 1,184
Extraordinary credit - (1,293)
Depreciation 4,185 4,227
Deferred income taxes and investment tax credits 412 1,723
Allowance for equity funds during construction (10) (17)
Net deferral and amortization of nuclear refueling
replacement energy and maintenance costs 2,185 (1,345)
Amortization of conservation and load management
costs 1,314 1,755
Amortization of capital leases 270 270
Decrease in accounts receivable and unbilled
revenues 4,235 4,482
Increase (decrease) in accounts payable (6,130) 3,364
Increase (decrease) in accrued income taxes 4,999 (2,171)
Change in other working capital items 5,289 (3,531)
Other, net (669) (513)
------- -------
Net cash provided by operating activities 28,436 16,626
------- -------
Investing Activities
Construction and plant expenditures (3,283) (3,242)
Conservation & load management expenditures (496) (568)
Return of capital 47 47
Non-utility investments (1,250) (100)
Other investments, net (4) (156)
------- -------
Net cash used for investing activities (4,986) (4,019)
------- -------
Financing Activities
Short-term debt, net - (400)
Long-term debt, net (6) (5)
Common and preferred dividends paid (2,522) (2,518)
Reduction in capital lease obligations (270) (270)
Sale of treasury stock - 29
------- -------
Net cash used for financing activities (2,798) (3,164)
------- -------
Net Increase in Cash and Cash Equivalents 20,652 9,443
Cash and Cash Equivalents at Beginning of Period 10,051 16,506
------- -------
Cash and Cash Equivalents at End of Period $30,703 $25,949
======= =======
Supplemental Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) $ 778 $ 586
Income taxes (net of refunds) $ 2,390 $ 5,851
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
March 31, 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.
PCB, INC. In August 1995, the Company received an Information Request from
the EPA pursuant to a Superfund investigation of two related sites, located in
Kansas and in Missouri (the Sites). During the mid-1980's, these Sites,
operated by PCB Treatment, Inc., received materials containing PCBs from
hundreds of sources, including the Company. According to the EPA, more than
1,200 parties have been identified as PRPs. The Company has complied with the
information request and will monitor EPA activities at the Sites. In
December 1996, the Company received an invitation to join a PRP steering
committee. The Company has not yet decided whether joining that committee
would be in its best interest. That committee has estimated the Company's pro
rata share of the waste sent to the Sites to be 0.42%. The committee
estimates that the Sites' remediation will cost between $5 million and
$40 million. Based on this information, the Company does not believe that the
Sites represent the potential for a material adverse effect on its financial
condition or results of operations.
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 the sites.
Note 3 - Retail Rates
Vermont: The Company's practice of reviewing costs periodically will
continue and rate increases will be requested when warranted. The Company
filed for a 6.6%, or $15.4 million per annum, general rate increase on
September 22, 1997 to become effective June 6, 1998 to offset increasing costs
of providing service. Approximately $14.3 million or 92.9% of the rate
increase request was to recover scheduled contractual increases in the cost of
power the Company purchases from Hydro-Quebec. At the same time, the Company
also filed a request to eliminate the winter-summer rate differential 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.
Several parties in the Company's rate case sought to challenge the
Company's decision in 1991 to "lock-in" its participation in its power
purchase agreement with Hydro-Quebec as one of 14 members of the Vermont Joint
Owners (VJO) claiming that the decision of the Company to commit to the power
contract in 1991 was imprudent and that power now purchased pursuant to that
agreement is not "used and useful." The parties have also claimed that the
Company has not met a condition of the PSB's prior approval of the contract,
requiring that the Company obtain all cost effective Demand Side Management.
In response, the Company filed a motion asking the PSB to rule that any
prudence and used and useful issues were resolved in prior proceedings and
that the PSB is precluded from again trying the Company on those issues.
On April 17, 1998, the PSB issued an order generally denying the
Company's motion. Given the fact that the PSB had severely penalized another
VJO member, Green Mountain Power Corporation (GMP), in an Order dated
February 27, 1998, after finding that its decision to lock-in the Hydro-Quebec
contract was imprudent and the power purchased pursuant to that lock-in was
not used and useful, the Company concluded that it was necessary to have the
so-called preclusion issue reviewed by the Vermont Supreme Court (VSC) before
the PSB issues a final order in the Company's 6.6% rate increase request.
As such, the Company and other parties requested that the PSB consent to the
filing of an interlocutory appeal of the PSB's decision and to a stay of the
rate case pending review by the VSC. The Company further agreed to toll the
statutory period of time in which the PSB must act on a rate request, while
the matter is in appeal. The resolution of this matter by the VSC is likely
to involve a remand to the PSB.
The appeal and associated stay of the rate case significantly delayed the
date that new rates would have otherwise taken effect. As a result, the
Company's earnings for 1998 were adversely affected.
In an effort to mitigate eroding earnings and cash flow prospects during
the VSC review process, on June 12, 1998 the Company filed with the PSB a
request for a 10.7% rate increase ($24.9 million of annualized revenues)
effective March 1, 1999. This rate case proceeding supplanted the 6.6% rate
increase request referenced above that is now stayed pending a review on the
so-called preclusion issue by the VSC. On October 27, 1998, the Company
reached an agreement with the Vermont Department of Public Service (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 common equity in its Vermont retail business at 11%
before disallowances in connection with the Hydro-Quebec Contract. The rate
increase is temporary insofar as it is subject to adjustment upon future
resolution of the Hydro-Quebec Contract issues presently before the VSC. The
Company anticipates a ruling by the VSC on the Hydro-Quebec Contract issues
before the end of 1999.
The agreement incorporates a disallowance of approximately $7.4 million
for the Company's purchased power costs under the Hydro-Quebec Contract while
the VSC reviews the PSB denial of the Company's claim that the PSB is
precluded from again trying the Company on certain Hydro-Quebec Contract
issues discussed above. This $7.4 million disallowance was calculated using
the same formula as contained in the rate order issued by the PSB in the GMP
rate case on February 28, 1998. Upon approval of the agreement by the PSB,
the Company, during the fourth quarter of 1998, recorded a loss of
$7.4 million on a pre-tax basis for disallowed purchased power costs
representing the Company's estimated under recovery of power costs under the
Hydro-Quebec Contract.
If the Company receives an unfavorable ruling from the VSC, and the PSB
issues a rate order adopting the methodology used to determine the temporary
Hydro-Quebec disallowance for the duration of the Hydro-Quebec Contract,
approximately $205.0 million of power costs to be incurred under that contract
would not be recoverable in rates. This would result in an immediate charge
to earnings of $205.0 million on a pre-tax basis once such outcome became
probable. Such an outcome would jeopardize the ability of the Company to
continue as a going concern.
New Hampshire: In an Order dated December 31, 1997 in Connecticut Valley
Electric Company Inc.'s (Connecticut Valley) Fuel Adjustment Clause (FAC) and
Purchased Power Cost Adjustment (PPCA) docket, the New Hampshire Public
Utilities Commission (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
Federal District Court (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 (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 (SFAS) No. 71. As a result, Connecticut
Valley wrote-off all of its regulatory assets associated with its New
Hampshire retail business as of December 31, 1997. This write-off amounted to
approximately $1.2 million on a pre-tax basis. In addition, Connecticut
Valley recorded a $5.5 million pre-tax loss in 1997 for disallowed power
costs.
On March 20, 1998, the NHPUC issued an order which affirmed, clarified
and modified various generic policy statements including the reaffirmation to
establish rates on the basis of a regional average announced previously in its
February 28, 1997 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 (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 (PSNH) and the other
utilities that have been allowed to intervene in these proceedings, including
the Company and Connecticut Valley. The plaintiffs-intervenors thereafter
filed a motion asking the Court to extend its stay of action by the NHPUC to
implement restructuring and to make clear that the stay encompasses the
NHPUC's order of March 20, 1998.
As a result of these Court orders, Connecticut Valley's 1997 charges,
described above, were reversed in the first quarter of 1998. Combined, the
reversal of these charges increased 1998 net income and earnings per share of
common stock by approximately $4.5 million and $.39, respectively.
On April 1, 1998, Citizens Bank of New Hampshire (Bank) notified
Connecticut Valley that it was in default of the Loan Agreement between the
Bank and Connecticut Valley dated December 27, 1994 and that the Bank would
exercise all of its remedies from and after May 5, 1998 in the event that the
violations were not cured. After reversing the 1997 write-offs described
above, Connecticut Valley was in compliance with the financial covenants
associated with its $3.75 million loan with the Bank. As a result,
Connecticut Valley satisfied the Bank's requirements for curing the violation.
On May 11, 1998 the NHPUC issued an order requiring Connecticut Valley to
show cause why it should not be held in contempt for its failure to meet the
compliance filing requirements of its March 20, 1998 Order. A hearing on this
matter was scheduled for June 11, 1998, which was subsequently canceled
because of the Court's June 5, 1998 Order, discussed below.
On June 5, 1998, the Court issued an Order which denied the NHPUC's
motion for a stay of the Court's preliminary injunction. The Order clearly
stated that no restructuring effort in New Hampshire can move forward without
the Court's approval unless all New Hampshire utilities agree to the plan.
The Order suspended all involuntary restructuring efforts for all
New Hampshire utilities until a hearing on the merits was conducted.
The NHPUC appealed this Order to the United States First Circuit Court of
Appeals (Court of Appeals).
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 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 the refund effective April 1, 1999.
On April 7, 1999, the Court ruled from the bench that the March 22, 1999
NHPUC Order which mandated Connecticut Valley to provide a refund to its
retail customers was illegal and the imposition of the refund went beyond the
authority of the NHPUC. 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 remaining stay of restructuring activities and indicated 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 Company expects the hearings
on the permanent injunction will take place later this year.
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. No order has been issued on this
matter.
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, 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, which are included in the estimated total
losses of $4.3 million discussed below.
As a result of legal and regulatory actions discussed above, Connecticut
Valley no longer qualifies for the application of SFAS No. 71, and wrote-off
all its regulatory assets associated with its New Hampshire retail business
estimated at approximately $1.3 million on a pre-tax basis. In addition,
Connecticut Valley recorded estimated total losses of $4.3 million pre-tax for
disallowed power costs of $1.6 million and 1998 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
allow 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 June 25, 1997, the Company filed with the FERC a notice of termination
of its power supply contract with Connecticut Valley, conditional upon the
Company's request to impose a surcharge on the Company's transmission tariff
to recover the stranded costs that would result from the termination of its
contract with Connecticut Valley. The amount requested was $44.9 million plus
interest at the prime rate to be recovered over a ten-year period. In its
Order dated December 18, 1997 in Docket No. ER97-3435-000, the FERC rejected
the Company's proposed stranded cost surcharge mechanism but indicated that it
would consider an exit fee mechanism for collecting stranded costs. The FERC
also rejected the Company's arguments concerning the applicability of stated
FERC policies regarding retail stranded costs, multi-state regulatory gaps and
the implications of state restructuring initiatives. The Company filed a
motion seeking rehearing of the FERC's December 18, 1997 Order which was
denied. Thereafter, the Company appealed the FERC decision to the Court of
Appeals for the District of Columbia circuit. In addition, and in accordance
with the December 18, 1997 FERC Order, on January 12, 1998 the Company filed a
request with the FERC for an exit fee mechanism to collect $44.9 million in a
lump sum, or in installments with interest at the prime rate over a ten-year
period, to cover the stranded costs resulting from the cancellation of
Connecticut Valley's power contract with the Company.
On March 11, 1998, the FERC issued an order accepting for filing the
Company's request for an exit fee effective March 14, 1998, and set hearings
to determine: whether Connecticut Valley will become an unbundled
transmission customer of the Company, the Company's expectation as to the
period of time it would serve Connecticut Valley, and the allowable amount of
the exit fee. The FERC also rejected the Company's June 25, 1997 notice of
termination indicating that the notice can be resubmitted when the power
contract is proposed to be terminated.
On April 28, 1998, the Company filed its case-in-chief before the FERC
updating the amount of the exit fee to $54.9 million in a lump sum, describing
all of the ways Connecticut Valley will become an unbundled transmission
customer of the Company subsequent to termination, and establishing the
expected period of service based upon the date of termination, whenever that
occurs, and the weighted average service life of its commitments to power
resources to serve Connecticut Valley. Had termination taken effect on
January 1, 1998 this expectation period would have equaled nineteen years.
On August 4 and 5, 1998 Phase 1 hearings were held at the FERC on the
issue of whether Connecticut Valley will become an unbundled transmission
customer of the Company. Subsequent to those hearings, the parties agreed to
go on to hearings on the Phase 2 issues (addressing the allowable amount of
the exit fee) without a preliminary determination from the Administrative Law
Judge or the FERC on the Phase 1 issues. The Company submitted supplemental
testimony on Phase 2 issues in December 1998 and the hearings were completed
on May 10, 1999.
From April 27 through May 10, 1999, nine days of hearings were held at
the FERC on the Phase II issues of (1) whether the Company has overcome the
rebuttable presumption that its expectation to provide wholesale power service
to Connecticut Valley extends beyond the one year termination notice provision
contained in its otherwise automatically renewing FERC regulated rate schedule
and (2) if rebutted, the amount of Connecticut Valley's stranded cost
obligation to be paid the Company as an exit fee. During the course of the
hearings, the Company reached a partial stipulation with the parties that
resulted in revision of its requested exit fee to approximately $48.0 million
had termination taken place on January 1, 1999.
If the Company is unable to obtain an order authorizing the full recovery
amount of the exit fee, or other appropriate mechanism, the Company would be
required to recognize a loss under this contract totaling approximately
$60.0 million on a pre-tax basis. Furthermore, the Company would be required
to write-off approximately $4.0 million in regulatory assets associated with
its wholesale business on a pre-tax basis. Conversely, even if the Company
obtains a FERC order authorizing the updated requested exit fee, Connecticut
Valley would be required to recognize a loss under this contract of
approximately $48.0 million on a pre-tax basis unless Connecticut Valley has
obtained an order by the NHPUC or other appropriate body directing the
recovery of those costs in Connecticut Valley's retail rates. Either of these
reasonably possible outcomes could occur during calendar year 1999.
The Company 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, cash flows, and ability to
obtain capital at competitive rates. 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 (Central Vermont) which engages in the purchase,
production, transmission, distribution and sale of electricity in Vermont;
Connecticut Valley Electric Company Inc. (Connecticut Valley) which
distributes and sells electricity in parts of New Hampshire; and Catamount
Energy Corporation (Catamount) which invests in non-regulated, energy-supply
projects. 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 markets energy-saving products, pursues
retail alliances to market energy and related products and services and
engages in the sale of or rental of electric water heaters, 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 its 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 months ended March 31, 1999 and 1998, is as
follows (dollars in thousands):
<TABLE>
<CAPTION>
Reclassifications
Central Vermont Connecticut Valley All & Consolidating
1999 Vermont New Hampshire Catamount Other(1) Entries
Consolidated
---- --------------- ------------------ --------- -------- ---------------- ------------
<S> <C> <C> <C> <C> <C> <C>
Revenues from external
customers $ 92,259 $ 6,385 $ 129 $ 2,322 $2,453 $ 98,642
Intersegment revenues 3,323 3,323 -
Net income (loss) 12,211 53 605 (139) - 12,730
Total assets 482,666 12,169 43,861 5,963 5,020 539,639
1998
Revenues from external
customers $ 78,294 $ 5,664 $ 66 $ 472 $ 538 $ 83,958
Intersegment revenues 3,443 3,443 -
Net income (loss) before
extraordinary credit 5,508 3,593 738 (448) - 9,391
Net income (loss) 5,508 4,466 738 (448) - 10,264
Total assets 484,794 14,747 40,991 2,741 5,974 537,299
(1) Includes segments below the quantitative threshold for separate disclosure.
</TABLE>
Note 5 - Investment in Vermont Yankee Nuclear Power Corporation
The Company accounts for its investment in Vermont Yankee using the
equity method. Summarized financial information for Vermont Yankee Nuclear
Power Corporation follows:
Three Months Ended March 31
1999 1998
Operating revenues $43,777 $51,170
Operating income $ 3,786 $ 3,760
Net income $ 1,656 $ 1,702
Company's equity in net income $518 $510
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
March 31, 1999
Earnings Overview
Net income and earnings per share of common stock for the quarter ended
March 31, 1999 were $12.7 million and $1.07 compared to $10.3 million and $.86
for the corresponding period last year.
Improved net income and earnings per share of common stock for 1999
reflect the postive impact of a 4.7% temporary Vermont retail rate increase
effective with service rendered January 1, 1999 ($3.0 million after-tax, or
$.26 per share of common stock) as well as a 3.7% increase in retail MWH
sales. Other factors affecting results for 1999 are described in Results of
Operations below.
First quarter 1998 reflects the positive impact of reversing Connecticut
Valley Electric Company Inc.'s (Connecticut Valley) 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 months ended
March 31, 1999 and 1998 (and the related percentage changes from 1998) is set
forth below:
<TABLE>
<CAPTION>
Three Months Ended March 31
Percentage Percentage
MWH Increase Revenues (000's) Increase
1999 1998 (Decrease) 1999 1998 (Decrease)
<S> <C> <C> <C> <C> <C> <C>
Residential 274,697 264,461 3.9 $38,693 $35,177 10.0
Commercial 235,320 228,432 3.0 30,324 27,462 10.4
Industrial 115,181 109,888 4.8 11,276 10,095 11.7
Other retail 1,538 1,802 (14.7) 439 483 (9.1)
--------- ------- ------- -------
Total retail sales 626,736 604,583 3.7 80,732 73,217 10.3
--------- ------- ------- -------
Resale sales:
Firm 914 674 35.6 42 19 121.1
Entitlement 99,368 85,012 16.9 4,731 4,984 (5.1)
Other 487,958 170,089 186.9 12,648 4,604 174.7
--------- ------- ------- -------
Total resale sales 588,240 255,775 130.0 17,421 9,607 81.3
--------- ------- ------- -------
Other revenues - - - 489 1,134 (56.9)
--------- ------- ------- -------
Total sales 1,214,976 860,358 41.2 $98,642 $83,958 17.5
========= ======= ======= =======
</TABLE>
Retail MWH sales for the first quarter of 1998 increased 3.7% compared to
the first quarter of 1998 reflecting a return to normal winter weather
compared to 1998. Retail revenues increased $7.5 million, or 10.3% compared
to last year. This variance is attributable to a $2.6 million impact of
higher MWH sales in the first quarter of 1999 as compared to the first quarter
of 1998 and $4.9 million resulting from the 4.7% temporary Vermont retail rate
increase discussed above.
For the first quarter of 1999, entitlement MWH sales increased 16.9%
while related revenues decreased 5.1% compared to the same period last year.
These variances result from the Vermont Yankee extended refueling outage in
1998.
Other resale sales increased 317,869 MWH and other resale revenues
increased $8.0 million for the first quarter of 1999 primarily as a result of
increased level of activity by the Company through its alliance with Virginia
Power in jointly supplying wholesale power in New England.
Other revenues decreased for the first quarter of 1999 due to a provision
for rate refunds of $.3 million related to a December 3, 1998 United States
Court of Appeals' (Court of Appeals) decision and January 4, 1999
New Hampshire Public Utilities Commission (NHPUC) order discussed below, and
to lower revenues associated with transmission interconnection agreements
partially offset by increased pole attachment rentals.
Net Purchased Power and Production Fuel Costs
The net cost components of purchased power and production fuel costs for
the three months ended March 31, 1999 and 1998 are as follows (dollars in
thousands):
<TABLE>
<CAPTION>
1999 1998
Units Amount Units Amount
<S> <C> <C> <C> <C>
Purchased and produced:
Capacity (MW) 1,084 $22,484 569 $20,441
Energy (MWH) 1,175,499 27,551 836,276 19,265
------- -------
Total purchased power costs 50,035 39,706
Production fuel (MWH) 115,414 616 75,075 515
------- -------
Total purchased power and
production fuel costs 50,651 40,221
Entitlement and other resale sales (MWH) 587,326 17,379 255,101 9,588
------- -------
Net purchased power and production
fuel costs $33,272 $30,633
======= =======
</TABLE>
Net purchased power and production fuel costs increased $2.6 million, or
8.6% for the first quarter of 1999 compared to the first quarter of 1998.
The 1999 first quarter 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. The 1998 first quarter reflects the positive impact
of reversing Connecticut Valley's fourth quarter 1997 charge of $5.5 million
pre-tax. Absent these non-recurring items, net purchased power and production
fuel costs decreased $1.0 million.
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.
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. (Velco) and
Public Service Company of New Hampshire (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 #3 of the Millstone Nuclear Power Station and owns a 2% equity interest
in Connecticut Yankee. These two plants are operated by Northeast Utilities
(NU). The Company also owns 2%, 3.5% and 31.3% equity interest in Maine
Yankee, Yankee Atomic and Vermont Yankee, respectively.
Millstone Unit #3
Millstone Unit #3 (Unit #3) resumed operation in June 1998, accordingly,
production fuel costs increased for the first quarter of 1999 compared to the
first quarter of 1998.
The Company remains actively involved with the other non-operating
minority joint-owners of Unit #3. This group is engaged in various activities
to monitor and evaluate NU and Northeast Utilities Service Co.'s efforts
relating to Unit #3. On August 7, 1997, the Company and eight other
non-operating owners of
Unit #3 filed a demand for arbitration with Connecticut
Light and Power Company and Western Massachusetts Electric Company and
lawsuits against NU and its trustees. The arbitration and lawsuits seek to
recover costs associated with replacement power, operation and maintenance
costs and other costs resulting from the shutdown of Unit #3. The
non-operating owners claim
that NU and two of its wholly owned subsidiaries failed
to comply with NRC's regulations, failed to operate the facility in accordance
with good operating practice and attempted to conceal their activities from
the non-operating owners and the NRC.
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 Federal Energy Regulatory Commission (FERC)
which, if approved by the FERC, would result in the settlement of 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. Approval of the settlement would also resolve 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 would 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.
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 $14.9 million,
$9.7 million and $2.4 million, respectively, at March 31, 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 will not have a material
adverse effect on the Company's earnings or financial condition.
Vermont Yankee
The Design Basis Documentation project (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 about
$6.2 million. Such costs will be 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 due diligence and negotiate a
possible agreement to purchase the assets of Vermont Yankee.
Production and Transmission
As a result of a settled transmission contract dispute with Hydro-Quebec,
production and transmission expenses decreased $.6 million for the first
quarter of 1999 compared to the first quarter of 1998.
Other Operation
Principally due to increased legal and regulatory expenses, other
operation expenses increased $.6 million for the first quarter of 1999
compared to the first quarter of 1998.
Maintenance
The decrease in maintenance expenses of about $1.0 million results
primarily from the severe ice storm in January 1998.
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 of
1999 results primarily from an increase in pre-tax earnings for the period.
Other Income and Deductions
The increase in other income, net for the 1999 first quarter results
primarily from lower expenditures related to SmartEnergy Service, Inc., a
wholly owned non-utility subsidiary of the Company.
Interest Expense
Due to the retirement of long-term debt in December 1998, interest
expense on long-term debt decreased for the 1999 first quarter compared to the
first quarter of 1998.
Other interest expense increased for the 1999 first quarter due to an
increase in outstanding short-term borrowings.
Extraordinary Credit
The 1998 extraordinary credit net of taxes of $.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 $28.4 million and $16.6 million for the three months
ended March 31, 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 three months of 1999 with cash and cash
equivalents of $30.7 million, an increase of $20.7 million from the beginning
of the year. The increase in cash for the first three months of 1999 was the
result of $28.4 million provided by operating activities, offset by
$5.0 million used for investing activities and $2.8 million used for financing
activities.
Operating Activities - Net income, depreciation and deferred income taxes
and investment tax credits provided $17.3 million. About $11.1 million of
cash was provided by working capital and other operating activities.
Investing Activities - Construction and plant expenditures consumed
approximately $3.3 million, while $1.7 million was used for C&LM programs and
non-utility investments.
Financing Activities - Dividends paid on common stock were $2.5 million
and reduction in capital lease obligations required $.3 million.
The level of short-term borrowings fluctuates based on seasonal corporate
needs, the timing of long-term financings and market conditions.
The Company has a $50.0 million revolving credit facility with a group of
banks maturing on June 1, 1999, of which $25.0 million was outstanding at
March 31, 1999. The Company expects that borrowings will be $25.0 million at
June 1, 1999. Additionally, the Company must rollover an aggregate of
$16.3 million of letters of credit between December 1999 and May 2000. In
addition, the Company has a $12.0 million accounts receivable facility which
matures in November 1999. The Company has agreed with its lenders to extend
the revolving credit facility to June 1, 2000, but with a reduced credit limit
of $40.0 million. An agreement has also been reached to extend the renewal
dates of the letters of credit to also be June 1, 2000. The Company expects
to close the extended revolving credit facility and letters of credit during
May 1999.
On March 12, 1999, Connecticut Valley was notified by Citizens Bank of
New Hampshire (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 (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. 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 February 17, 1999, Duff & Phelps Credit Rating Co. (Duff & Phelps)
placed the credit ratings of the Company on Rating Watch-Down due to the high
level of regulatory and public policy uncertainty in Vermont and the 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."
Current credit ratings by Duff & Phelps remain at 'BBB' (Triple-B) for
first mortgage bonds and 'BBB-' (Triple-B-Minus) for preferred stock.
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 BBB-
First Mortgage Bonds BBB BBB+
Preferred Stock BBB- BB+
On November 12, 1998, Catamount, a wholly owned non-utility subsidiary of
the Company, 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 non-utility wholly owned subsidiaries are
non-recourse to the Company.
Hydro-Quebec Contract
The Company is a party to a power contract with Hydro-Quebec through the
Vermont Joint Owners (VJO), a consortium of Vermont utilities which includes
the Company, Green Mountain Power Corporation (GMP), Citizen's Utilities,
Rochester Electric Light & Power and Vermont Public Power Supply Authority
representing municipalities and a cooperative in Vermont. Under these
agreements, there are "step up" provisions that provide that in the event any
VJO member fails to meet its obligation under the contract with Hydro-Quebec,
the balance of the VJO participants, including the Company, will "step up" to
the defaulting party's share on a pro-rata basis. As of March 31, 1999 the
Company's VJO obligation is approximately 46% or $1.0 billion on a nominal
basis over the term of the contract ending in 2016. The total VJO contract
obligation on a nominal basis over the term of the contract is approximately
$2.3 billion.
During January 1998, a significant ice storm affected parts of New York,
New England and the Province of Quebec, Canada. This storm damaged major
components of the Hydro-Quebec transmission system over which power is
supplied to Vermont under the VJO contract with Hydro-Quebec. This resulted
in an interruption of a significant portion of scheduled contractual power
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 in the future. That review has
prompted the VJO to initiate an arbitration proceeding, the end result of
which may be the termination of the contract. By way of the arbitration, the
VJO is also seeking to recover capacity payments made during the period of
non-delivery.
Diversification Catamount was formed for the purpose of investing in
non-regulated power plant
projects. Currently, Catamount, through its wholly
owned subsidiaries, has interests in five operating independent power projects
located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate,
Vermont; and Hopewell, Virginia. In addition, Catamount has interests in
projects under construction in Thetford, England, and in Summersville,
West Virginia, and under development in Fort Dunlop, England. Catamount's
after-tax earnings were $.6 million and $.7 million for the first quarter 1999
and 1998, respectively.
SmartEnergy was formed to engage in the sale of or rental of electric
water heaters, energy efficient products and other related goods and services.
Currently, SmartEnergy, through its subsidiaries, has signed an agreement to
have its SmartDrive dairy vacuum pump control manufactured and deliverd to
domestic and worldwide markets; administers a fixed for variable rate swap
contract for the cost of electrical service with two customers located in the
state of Virginia, and has entered into a Test Marketing and License Agreement
with Sam's Club, Inc. for the purpose of test marketing certain home service
solution products and services to Sam's Club members at four test market
locations which is scheduled to begin by the end of May 1999. SmartEnergy
incurred losses of $.1 million and $.4 million for the first quarter 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 passed on to consumers through automatic rate adjustment clauses.
The Company's practice of reviewing costs periodically will continue and rate
increases will be requested 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
overlapped 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 (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 rate increase is temporary insofar as it is
subject to adjustment upon future resolution of the Hydro-Quebec Contract
issues presently before the VSC. The Company anticipates a ruling by the VSC
on the Hydro-Quebec issues the end of 1999.
The agreement incorporates a disallowance of approximately $7.4 million
for the Company's purchased power costs under the Hydro-Quebec Contract while
the VSC reviews the PSB denial of the Company's claim that the PSB is
precluded from again trying the Company on certain Hydro-Quebec Contract
issues. This $7.4 million disallowance was calculated using the same formula
as contained in the rate order issued by the PSB in the GMP rate case on
February 28, 1998. Upon approval of the agreement by the PSB, the Company,
during the fourth quarter of 1998, recorded a loss of $7.4 million on a
pre-tax basis for
disallowed purchased power costs, representing the Company's
estimated under recovery of power costs under the Hydro-Quebec Contract.
If the Company receives an unfavorable ruling from the VSC, and the PSB
issues a rate order adopting the methodology used to determine the temporary
Hydro-Quebec disallowance for the duration of the Hydro-Quebec Contract,
approximately $205.0 million of power costs to be incurred under that contract
would not be recoverable in rates. This would result in an immediate charge
to earnings of $205.0 million on a pre-tax basis once such outcome became
probable. Such an outcome would 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 winter-summer rate differential 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.
The PSB decided to appoint an independent investigator to examine the
Company's decision to buy power from Hydro-Quebec. The Company filed a motion
with the PSB stating that the PSB already examined the Company's decision to
buy power from Hydro-Quebec and, therefore, the PSB as well as other parties
should be barred from reviewing its past decision on Hydro-Quebec. However,
the Company does not object to the independent investigator or others looking
at issues of management of the power supply since the Company's last rate
case.
During February 1998, the DPS filed testimony in opposition to the
Company's 6.6% or $15.4 million retail rate increase request. As a result of
its testimony, the DPS recommended that the PSB instead reduce the Company's
current retail rates by 2.5% or $5.7 million.
On February 28, 1998 the PSB issued an Order in a GMP rate case. That
Order found GMP'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. GMP 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 GMP February 28, 1998 rate order, the
Company's ability to continue as a going concern would 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 (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.
New Hampshire: On November 26, 1997, Connecticut Valley filed a request
with the NHPUC to increase the Fuel Adjustment Clause (FAC) and Purchased
Power Cost Adjustment (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 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
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. 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, 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
non-utility
subsidiaries, Catamount and SmartEnergy. The Company believes that a
holding company structure will facilitate the Company's transition to a
deregulated electricity market. The proposed holding company formation must
also be approved by Federal regulators, including the Securities and Exchange
Commission and the FERC, and by the Company's shareholders.
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 activities are 100% complete. The Company expects to achieve
compliance with Year 2000 requirements for all of its financial and operating
systems by the end of the second quarter of 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 will be compliant by July 1999. 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.
Failure on the part of the Company to comply by December 31, 1999 could
have a material adverse effect on the Company's results of operations and
financial condition. Also, 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 $3.6 million of costs
associated with making the necessary modifications to its centralized and
non-centralized computer systems. As of March 31, 1999, approximately
$3.2 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 the regulatory process.
ELECTRIC INDUSTRY RESTRUCTURING
The electric utility industry is in a period of transition that may
result in a shift away from ratemaking 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
On December 31, 1996, the PSB issued a Report and Order (the Report)
outlining a restructuring plan (the Plan), subject to legislative approval,
for the Vermont electric utility industry.
Due to uncertainty surrounding legislative schedules, the PSB, on
April 18, 1997, issued an Order which suspended, pending further legislative
action or future PSB Orders, certain filing deadlines for reports and plans to
be completed in connection with the Plan.
On April 3, 1997, Senate Bill 62 (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 and could have chosen their electricity supplier.
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 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
Statement of Financial Accounting Standards (SFAS) No. 71. S.62 also created
an incentive for the Company 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
would have had to be passed by the Vermont House of Representatives and signed
by the Governor of the State of Vermont. Since the 1998 Legislative session
concluded in April 1998 and S.62 was not enacted by the Vermont House of
Representatives and subsequently signed into law by the Governor of Vermont,
the bill did not become law and any efforts to pursue it in the future will
require that it be re-enacted by the Vermont Senate and passed by the Vermont
House of Representatives.
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 recommendations in a report and legislation was proposed that would
have provided for reform but not adopt the recommendations concerning customer
choice and competition set forth in the PSB's Report and Order. Other
legislation intended to advance a portion of the PSB Report and Order was also
introduced. However, neither the House of Representatives nor Vermont Senate
acted on these reforms which must be reintroduced in the next Vermont
legislative biennium that began in January 1999, if they are to be considered.
Therefore, at this time, it cannot be determined whether future restructuring
legislation will be enacted in 1999 that would conform to the concepts
developed by the Report, S.62 or the House Special Committee report.
On July 22, 1998, Governor Dean issued an Executive Order establishing a
Working Group on Vermont's Electricity Future (the Working Group) 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 can 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 Governor Dean to gather information on and evaluate the possible
consequences of the current financial status of Vermont electric utilities.
The Working Group was asked to complete its review and report back to Governor
Dean and to legislative leaders by December 15, 1998.
A report was issued by the Working Group on December 18, 1998. Key
conclusions of its report are:
1. Vermont should restructure its electric industry by moving rapidly to
retail choice whereby consumers would purchase power directly from competing
power suppliers.
2. Bankruptcy of Vermont electric utilities should not be viewed as an
appropriate means to reduce Vermont utilities' above market power supply
costs.
3. 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.
4. The Vermont electric utilities should pursue auctions of their power
generation assets and remaining power contracts.
5. 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 rates in the nation, electricity costs in Vermont have been
among the lowest in the region. However, that advantage is eroding as other
states in New England restructure their electric utility industries.
Therefore, the Working Group recommends that it is in the interest of Vermont
ratepayers to have the benefit of a restructured electric utility industry as
soon as possible.
The Company has signed a confidentiality and cooperation agreement with
GMP and Citizens Utilities to permit an exchange of information to evaluate
the possibility of consolidating the Vermont operations of the three
utilities. In addition, the Washington Electric Cooperative (WEC) has
recommended that consideration be given to its acquiring Vermont's investor
owned utilities and converting them to a cooperative ownership structure. The
Company also signed a confidentiality and cooperation agreement with WEC.
The Company supports the Working Group recommendations and believes that
they can be implemented without legislative change. During the first quarter
of 1999 the Company and GMP filed with the PSB a plan that would bring
electric industry competition to Vermont, stabilize power costs and
streamline energy-efficiency programs as follows:
1. The Company and GMP would voluntary give up the exclusive right to serve
their present electricity customers, allowing competitive electricity sales to
about 70% of the electric customers in the state in the context of a global
settlement.
2. The Company and GMP would refinance and renegotiate Hydro-Quebec and Small
Power Producers' power contracts to bring down the costs.
3. The Company and GMP would evaluate wholly owned and jointly owned
generating sources, including Vermont Yankee, and decide which ones were most
appropriate for sale. Efforts to sell Vermont Yankee are already under way.
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.
4. The state of Vermont would create an efficiency utility to streamline
energy-efficiency services for electric customers. As further discussed
below, the Company and GMP have entered into a Memorandum of Understanding
with the DPS for the creation of an energy efficiency utility.
5. In the future, a petition may be filed with regulators that could lead to
the consolidation of some of Vermont's electric distribution companies into a
new company.
The Company believes that this plan provides Vermont with the best
opportunity to stabilize customer rates, open markets to competition and
return the electric industry to sound footing. The Company expects to
formally submit its proposal to the PSB during the fall of 1999.
On August 27, 1998, the PSB hosted a workshop entitled, "Electricity
Futures: Reforming Vermont's Power Supply", which was organized to facilitate
power supply reform. Participants heard reports on successful power supply
reforms in other states, followed by a discussion intended to identify
opportunities and next steps, and to elicit proposals for reformulating
Vermont's electric power supply. This workshop generated a great deal of
interest with over 140 attendees, representing Vermont retail electric
utilities, both large and small electricity consumers, public officials and
interest groups, and several current and aspiring energy suppliers. As a
follow up to the workshop, 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
explained that it intends that this proceeding will define one or more
acceptable courses for reform, and will create the framework to enable Vermont
utilities and other interested parties to pursue them and to present them for
regulatory approval in an open, public process. 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 well as the WEC acquisition proposal. 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 intends to issue final, binding and
appealable orders concerning matters related to the reform and restructuring
of Vermont's electric utility industry. Initially, the PSB noticed 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 will include 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. The PSB explains that
this proceeding will provide utilities the maximum structural guidance on the
terms and conditions it will consider in a voluntary restructuring proposal.
As of this time, formal proceedings in Docket No. 6140-A are only at a
preliminary status, however the PSB indicates that it will proceed quickly to
conclude this proceeding.
Consistent with the Company's restructuring plan, on April 30, 1999 the
Company and GMP entered into a Memorandum of Understanding (the MOU) with the
DPS for the creation of an energy efficiency utility (EEU) to provide
system-wide DSM services.
Subsequently, other Vermont utilities including Citizens
Utilities and the Vermont Electric Coop, 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 EEU, the design of the EEU programs and services,
and the EEU budgets. The MOU also resolves all claims based on actions or
failures to act prior to January 1, 2000 that the Company failed to satisfy
its DSM obligations to customers under Vermont law and regulation. The PSB is
currently considering the approval of the MOU which is expected by summer of
1999. If approved by the PSB, the new energy efficiency delivery system would
be in place beginning in year 2000 and would replace services now provided to
customers by the Company.
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 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 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
Federal District Court (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 April 3, 1998, the Court held a hearing on the Companies' motion for a
Temporary Restraining Order (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 have been allowed to
intervene in these proceedings, including the Company and Connecticut Valley.
The plaintiffs-intervenors 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 (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 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.
On April 7, 1999, the Court ruled from the bench that the March 22, 1999
NHPUC Order which mandated Connecticut Valley to provide a refund to its
retail customers was illegal and the imposition of the refund went beyond the
authority of the NHPUC. 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 remaining stay of restructuring activities and indicated 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 Company expects the hearings
on the permanent injunction will take place later this year.
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. No order has been issued on this
matter.
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, which are included in the estimated total
losses of $4.3 million discussed below.
As a result of legal and regulatory actions discussed above, Connecticut
Valley no longer qualifies for the application of SFAS No. 71, and wrote-off
all its regulatory assets associated with its New Hampshire retail business
estimated at approximately $1.3 million on a pre-tax basis. In addition,
Connecticut Valley recorded estimated total losses of $4.3 million pre-tax for
disallowed power costs of $1.6 million and 1998 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 forums.
The pre-tax losses described above resulted in Connecticut Valley
violating applicable covenants, which if not waived or renegotiated, would
allow 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 June 25, 1997, the Company filed with the FERC a notice of termination
of its power supply contract with Connecticut Valley, conditional upon the
Company's request to impose a surcharge on the Company's transmission tariff
to recover the stranded costs that would result from the termination of its
contract with Connecticut Valley. The amount requested was $44.9 million plus
interest at the prime rate to be recovered over a ten-year period. In its
Order dated December 18, 1997 in Docket No. ER97-3435-000, the FERC rejected
the Company's proposed stranded cost surcharge mechanism but indicated that it
would consider an exit fee mechanism for collecting stranded costs. The FERC
also rejected the Company's arguments concerning the applicability of stated
FERC policies regarding retail stranded costs, multi-state regulatory gaps and
the implications of state restructuring initiatives. The Company filed a
motion seeking rehearing of the FERC's December 18, 1997 Order which was
denied. Thereafter, the Company appealed the FERC's decision to the Court of
Appeals for the District of Columbia circuit. In addition, and in accordance
with the December 18, 1997 FERC Order, on January 12, 1998 the Company filed a
request with the FERC for an exit fee mechanism to collect $44.9 million in a
lump sum, or in installments with interest at the prime rate over a ten-year
period, to cover the stranded costs resulting from the cancellation of
Connecticut Valley's power contract with the Company.
On March 11, 1998, the FERC issued an order accepting for filing the
Company's request for an exit fee effective March 14, 1998, and set hearings
to determine: whether Connecticut Valley will become an unbundled
transmission customer of the Company, the Company's expectation as to the
period of time it would serve Connecticut Valley, and the allowable amount of
the exit fee. The FERC also rejected the Company's June 25, 1997 notice of
termination indicating that the notice can be resubmitted when the power
contract is proposed to be terminated.
On April 28, 1998, the Company filed its case-in-chief before the FERC
updating the amount of the exit fee to $54.9 million in a lump sum, describing
all of the ways Connecticut Valley will become an unbundled transmission
customer of the Company subsequent to termination, and establishing the
expected period of service based upon the date of termination, whenever that
occurs, and the weighted average service life of its commitments to power
resources to serve Connecticut Valley. Had termination taken effect on
January 1, 1998 this expectation period would have equaled nineteen years.
On August 4 and 5, 1998 Phase 1 hearings were held at the FERC on the
issue of whether Connecticut Valley will become an unbundled transmission
customer of the Company. Subsequent to those hearings, the parties agreed to
go on to hearings on the Phase 2 issues (addressing the allowable amount of
the exit fee) without a preliminary determination from the Administrative Law
Judge or the FERC on the Phase 1 issues. The Company submitted supplemental
testimony on Phase 2 issues on December 3, 1998 and the hearings were
completed on May 10, 1999.
From April 27 through May 10, 1999, nine days of hearings were held at
the FERC on the Phase II issues of (1) whether the Company has overcome the
rebuttable presumption that its expectation to provide wholesale power service
to Connecticut Valley extends beyond the one year termination notice provision
contained in its otherwise automatically renewing FERC regulated rate schedule
and (2) if rebutted, the amount of Connecticut Valley's stranded cost
obligation to be paid the Company as an exit fee. During the course of the
hearings, the Company reached a partial stipulation with the parties that
resulted in revision of its requested exit fee to approximately $48.0 million
had termination taken place on January 1, 1999.
If the Company is unable to obtain an order authorizing the full recovery
amount of the exit fee, or other appropriate mechanism, the Company would be
required to recognize a loss under this contract totaling approximately
$60.0 million on a pre-tax basis. Furthermore, the Company would be required
to write-off approximately $4.0 million in regulatory assets associated with
its wholesale business on a pre-tax basis. Conversely, even if the Company
obtains a FERC order authorizing the updated requested exit fee, Connecticut
Valley would be required to recognize a loss under this contract of
approximately $48.0 million on a pre-tax basis unless Connecticut Valley has
obtained an order by the NHPUC or other appropriate body directing the
recovery of those costs in Connecticut Valley's retail rates. Either of these
reasonably possible outcomes could occur during calendar year 1999.
The Company 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, cash flows, and ability to
obtain capital at competitive rates. 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
and 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 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
Report 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 $63.7 million on a pre-tax basis as
of March 31, 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 two 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 Unit #3 filed a demand for arbitration with Connecticut Light and Power
Company and Western Massachusetts Electric Company and lawsuits against NU and
its trustees. The arbitration and lawsuits seek to recover costs associated
with replacement power, operation and maintenance costs and other costs
resulting from the shutdown of Unit #3. The non-operating owners claim that
NU and two of its wholly owned subsidiaries failed to comply with NRC's
regulations, failed to operate the facility in accordance with good operating
practice and attempted to conceal their activities from the non-operating
owners and the NRC.
Except as otherwise described under Management's Discussion and
Analysis of Financial Condition and Results of Operations, Item 2, there are
no other material pending legal proceedings, other than ordinary routine
litigation incidental to the business, to which the Company or any of its
subsidiaries is a party or to which any of their property is subject.
Items 2 and 3.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
(a) The Registrant held its Annual Meeting of Stockholders on May 4,
1999.
(b) Director elected whose term will expire in year 2001:
Votes FOR Votes WITHHELD
Janice L. Scites 9,170,580 236,696
Directors elected whose terms will expire in year 2002:
Votes FOR Votes WITHHELD
Rhonda L. Brooks 9,185,903 221,373
Patrick J. Martin 9,194,841 212,435
Robert H. Young 9,187,899 219,377
Other Directors whose terms will expire in 2000:
Frederic H. Bertrand
Robert L. Barnett
Robert G. Clarke
Mary Alice McKenzie
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). At this time, no date has been
selected for the necessary confirming vote by qualified Claremont
voters. The Company intends to vigorously pursue its rights.
Item 6. Exhibits and Reports on Form 8-K.
(a) List of Exhibits
10. Material Contracts
A 10.89 Management Incentive Plan for Executive Officers
dated January 1, 1999
A - compensation related plan, contract or arrangement
27. Financial Data Schedule
(b) Item 5. Other Events, dated February 2, 1999 re: Standard &
Poor's Corporation lowering the Company's corporate credit
rating.
<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 May 13, 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> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> MAR-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 318046
<OTHER-PROPERTY-AND-INVEST> 66383
<TOTAL-CURRENT-ASSETS> 86418
<TOTAL-DEFERRED-CHARGES> 68792
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 539639
<COMMON> 66481
<CAPITAL-SURPLUS-PAID-IN> 45324
<RETAINED-EARNINGS> 80013
<TOTAL-COMMON-STOCKHOLDERS-EQ> 191453
17000
8054
<LONG-TERM-DEBT-NET> 90071
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 6773
1000
<CAPITAL-LEASE-OBLIGATIONS> 15871
<LEASES-CURRENT> 1094
<OTHER-ITEMS-CAPITAL-AND-LIAB> 208323
<TOT-CAPITALIZATION-AND-LIAB> 539639
<GROSS-OPERATING-REVENUE> 98642
<INCOME-TAX-EXPENSE> 7557
<OTHER-OPERATING-EXPENSES> 77230
<TOTAL-OPERATING-EXPENSES> 84787
<OPERATING-INCOME-LOSS> 13855
<OTHER-INCOME-NET> 1464
<INCOME-BEFORE-INTEREST-EXPEN> 15319
<TOTAL-INTEREST-EXPENSE> 2589
<NET-INCOME> 12730
465
<EARNINGS-AVAILABLE-FOR-COMM> 12265
<COMMON-STOCK-DIVIDENDS> 0
<TOTAL-INTEREST-ON-BONDS> 1573
<CASH-FLOW-OPERATIONS> 28436
<EPS-PRIMARY> 1.07
<EPS-DILUTED> 1.07
</TABLE>
EXHIBIT A 10.89
- - - - - - - - - - - - - -----------------------
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
MANAGEMENT INCENTIVE PLAN
Adopted As Of January 1, 1999
I. PURPOSE
The Company's executive officers participate in the Company's
annual Management Incentive Plan (the "MIP"). The purpose of the
MIP is to focus the efforts of the executive team on the
achievement of challenging and demanding corporate objectives.
When corporate performance attains the specified annual
performance objectives, an award is granted. This incentive
plan, in conjunction with competitive salaries and long-term
incentives, provides a level of compensation which rewards the
skills and efforts of the executives commensurate with market
comparisons.
II. ADMINISTRATION
The MIP will be administered by the Compensation Committee of the
Board of Directors (the "Committee"). All Committee actions will
be subject to review and approval by the full Board of Directors
(the "Board").
At the beginning of each year ("Plan Year"), the Committee will
submit to the Board its recommendations for that Plan Year as to
(i) the MIP's Corporate Performance Goals, and (ii) the eligible
participants. After the end of each Plan Year, the Committee
will report to the Board with respect to achievement of the
approved Corporate Performance Goals and individual performance
measures for that Plan Year, and will submit to the Board its
recommendations as to the appropriate award payment levels for
each eligible participant. Recommendations of the Committee,
with such modifications as may be made by the Board, will be
binding on all participants in the MIP.
III. THE PLAN
Performance measures must be met in the following areas to
receive an award. Each measure is equally weighted, representing
one-third of the potential payout.
Consolidated earnings per share. Consolidated earnings per share
measures the overall financial performance of the company.
Customer satisfaction. Measures (1) the overall degree of
satisfaction by all customers and (2) the level of satisfaction
with specific service by customers who have had a recent service
interaction. The measurement is conducted by an external firm.
Individual performance. Performance is measured vs. objectives
for the year for each Executive Officer based on advice and
recommendation from the Chief Executive Officer. The Committee
and Board evaluate the Chief Executive Officer's performance vs.
his objectives.
The total award if the maximum payout on all three of these
measures were to be met, would represent 35% of base salary for
the Chief Executive Officer; 25% of base salary for the Senior
Vice Presidents and Vice President and General Manager for
Business Development; 20% for other Vice Presidents and Assistant
Vice Presidents. If the targeted level of EPS is exceeded, the
total award is increased by 10%.
IV. AWARDS
Any annual incentive award will consist of cash (50%) and Central
Vermont Public Service Corporation stock (50%) which will have a
three year vesting restriction. The restricted stock portion has
an additional 25% premium. Applicable dividends will be paid on
awarded restricted stock prior to vesting.
V. AMENDMENTS
The Board reserves the right to amend, modify or terminate the
MIP at any time.
