SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
Form 10-Q
x QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1998
TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to _______
Commission file number 1-8222
Central Vermont Public Service Corporation
(Exact name of registrant as specified in its charter)
Incorporated in Vermont 03-0111290
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
77 Grove Street, Rutland, Vermont 05701
(Address of principal executive offices) (Zip Code)
802-773-2711
(Registrant's telephone number, including area code)
______________________________________________________________________________
(Former name, former address and former fiscal year, if changed since last
report)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No ____
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date. As of July 31, 1998 there
were outstanding 11,442,376 shares of Common Stock, $6 Par Value.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q
Table of Contents
Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statement of Income and Retained Earnings
for the six months ended June 30, 1998 and 1997 3
Consolidated Balance Sheet as of June 30, 1998 and
December 31, 1997 4
Consolidated Statement of Cash Flows for the six
months ended June 30, 1998 and 1997 5
Notes to Consolidated Financial Statements 6-11
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 12-27
PART II. OTHER INFORMATION 28-29
SIGNATURE 30
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENT OF INCOME AND RETAINED EARNINGS
(Dollars in thousands, except per share amounts)
(Unaudited)
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
---- ---- ---- ----
Operating Revenues $66,406 $65,442 $150,364 $153,936
Operating Expenses
Operation
Purchased power 45,882 40,305 85,588 81,301
Production and transmission 5,766 5,610 11,354 11,287
Other operation 11,419 10,698 22,853 20,683
Maintenance 3,802 3,685 7,654 6,726
Depreciation 4,231 4,229 8,458 8,689
Other taxes, principally
property taxes 2,804 2,718 5,844 5,706
Taxes on income (3,419) (918) 2,013 6,289
------- ------- -------- --------
Total operating expenses 70,485 66,327 143,764 140,681
------- ------- -------- --------
Operating Income (Loss) (4,079) (885) 6,600 13,255
------- ------- -------- --------
Other Income and Deductions
Equity in earnings of
affiliates 844 792 1,576 1,677
Allowance for equity funds
during construction 11 24 28 44
Other income, net 354 1,012 932 3,756
Benefit (provision) for income
taxes 52 (149) 62 (1,031)
------- ------- -------- --------
Total other income and
deductions, net 1,261 1,679 2,598 4,446
------- ------- -------- --------
Total Operating and Other
Income (Loss) (2,818) 794 9,198 17,701
Net Interest Expense 2,634 2,649 5,259 5,237
------- ------- -------- --------
Net Income (Loss) Before
Extraordinary Credit (5,452) (1,855) 3,939 12,464
Extraordinary Credit Net of
Taxes - - 873 -
------- ------- -------- --------
Net Income (Loss) (5,452) (1,855) 4,812 12,464
Retained Earnings at Beginning
of Period 85,613 85,415 75,841 74,137
------- ------- -------- --------
80,161 83,560 80,653 86,601
Cash Dividends Declared
Preferred stock 487 507 973 1,014
Common stock 5,028 5,070 5,034 7,604
------- ------- -------- --------
Total dividends declared 5,515 5,577 6,007 8,618
------- ------- -------- --------
Retained Earnings at End of
Period $74,646 $77,983 $ 74,646 $ 77,983
======= ======= ======== ========
Earnings (Losses) Available
For Common Stock $(5,939) $(2,362) $ 3,839 $ 11,450
Average Shares of Common Stock
Outstanding 11,425,725 11,469,837 11,424,843 11,494,655
Basic and Diluted Share of
Common Stock:
Earnings (losses) before
extraordinary credit $(.52) $(.21) $.26 $1.00
Extraordinary credit - - .08 -
----- ----- ---- -----
Earnings (Losses) Per Basic and
Diluted Share of Common Stock $(.52) $(.21) $.34 $1.00
===== ===== ==== =====
Dividends Paid Per Share of
Common Stock $.22 $.22 $.44 $.44
The accompanying notes are an integral part of these consolidated financial
statements.
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED BALANCE SHEET
(Dollars in thousands)
June 30 December 31
1998 1997
---- ----
Assets
Utility Plant, at original cost $462,512 $461,482
Less accumulated depreciation 158,873 151,250
-------- --------
303,639 310,232
Construction work in progress 15,067 10,450
Nuclear fuel, net 947 964
-------- --------
Net utility plant 319,653 321,646
-------- --------
Investments and Other Assets
Investments in affiliates, at equity 26,121 26,495
Non-utility investments 35,256 33,736
Non-utility property, less accumulated depreciation 2,787 2,894
-------- --------
Total investments and other assets 64,164 63,125
-------- --------
Current Assets
Cash and cash equivalents 8,777 16,506
Special deposits 340 404
Accounts receivable, less allowance for uncollectible
accounts ($1,961 in 1998 and $1,946 in 1997) 21,196 23,166
Unbilled revenues 12,369 18,951
Materials and supplies, at average cost 3,868 3,779
Prepayments 1,485 1,464
Other current assets 5,395 4,970
-------- --------
Total current assets 53,430 69,240
-------- --------
Regulatory Assets 73,343 73,209
-------- --------
Other Deferred Charges 4,960 4,720
-------- --------
Total Assets $515,550 $531,940
======== ========
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 45,307 45,295
Treasury stock (353,447 shares and 362,447 shares,
respectively, at cost) (4,610) (4,728)
Retained earnings 74,646 75,841
-------- --------
Total common stock equity 186,058 187,123
Preferred and preference stock 8,054 8,054
Preferred stock with sinking fund requirements 18,000 19,000
Long-term debt 108,839 93,099
Long-term lease arrangements 16,682 17,223
-------- --------
Total capitalization 337,633 324,499
-------- --------
Current Liabilities
Short-term debt 250 12,650
Current portion of long-term debt and preferred stock 21,521 24,271
Accounts payable 5,643 4,609
Accounts payable - affiliates 11,412 12,441
Accrued income taxes (3,721) 6,631
Dividends declared 3,000 2,513
Nuclear decommissioning costs 6,010 6,010
Other current liabilities 16,021 21,646
-------- --------
Total current liabilities 60,136 90,771
-------- --------
Deferred Credits
Deferred income taxes 56,780 53,996
Deferred investment tax credits 7,026 7,222
Nuclear decommissioning costs 26,020 28,947
Other deferred credits 27,955 26,505
-------- --------
Total deferred credits 117,781 116,670
-------- --------
Total Capitalization and Liabilities $515,550 $531,940
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)
(Unaudited)
Six Months Ended
June 30
1998 1997
---- ----
Cash Flows Provided (Used) By
Operating Activities
Net income $ 4,812 $12,464
Adjustments to reconcile net income to net cash
provided by operating activities
Equity in earnings of affiliates (1,576) (1,677)
Dividends received from affiliates 1,312 1,605
Equity in earnings of non-utility investments (3,046) (2,491)
Distribution of earnings from non-utility
investments 1,663 2,209
Extraordinary credit (1,294) -
Depreciation 8,458 8,689
Deferred income taxes and investment tax credits 2,928 (286)
Allowance for equity funds during construction (28) (44)
Net deferral and amortization of nuclear refueling
replacement energy and maintenance costs (4,168) 2,781
Amortization of conservation and load management
costs 3,509 3,509
Gain on sale of property - (2,095)
Decrease in accounts receivable and unbilled
revenues 9,560 13,236
Increase (decrease) in accounts payable 315 (1,496)
Increase (decrease) in accrued income taxes (10,352) 494
Change in other working capital items (6,394) 2,901
Other, net 698 (1,337)
------- -------
Net cash provided by operating activities 6,397 38,462
------- -------
Investing Activities
Construction and plant expenditures (6,935) (6,922)
Deferred conservation & load management expenditures (1,195) (806)
Return of capital 93 93
Proceeds from sale of property - 2,624
Non-utility investments (100) (776)
Other investments, net (178) 137
------- -------
Net cash used for investing activities (8,315) (5,650)
------- -------
Financing Activities
Sale (repurchase) of common stock 112 (1,072)
Short-term debt, net (400) (5,760)
Long-term debt, net (10) -
Common and preferred dividends paid (5,513) (6,082)
------- -------
Net cash used for financing activities (5,811) (12,914)
------- -------
Net Increase (Decrease) in Cash and Cash Equivalents (7,729) 19,898
Cash and Cash Equivalents at Beginning of Period 16,506 6,365
------- -------
Cash and Cash Equivalents at End of Period $ 8,777 $26,263
======= =======
Supplemental Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) $ 5,106 $ 4,748
Income taxes (net of refunds) $ 9,777 $ 7,164
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1998
Note 1 - Accounting Policies
The Company's significant accounting policies are described in Note 1 of
Notes to Consolidated Financial Statements included in its 1997 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.
See Note 3 below for detail in regard to a Court Order issued on April 9, 1998
by the United States Court for the District of New Hampshire, sitting in
Rhode Island (Court) which again qualifies Connecticut Valley Electric Company
Inc. (Connecticut Valley), the Company's New Hampshire subsidiary, to prepare
its financial statements in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71.
RECLASSIFICATION Certain reclassifications have been made to prior year
Consolidated Financial Statements to conform with the 1998 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. For related information see Part II
Item 1, Legal Proceedings below.
CLEVELAND AVENUE PROPERTY One such site is 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 million. This was charged to expense in the
fourth quarter of 1992. Site investigation continued over the next several
years.
In January of 1995, the Company was formally contacted by the EPA asking
for written consent to conduct a site evaluation of the Cleveland Avenue
property. That evaluation has been completed. The Company does not believe
the EPA's evaluation changes its potential liability so long as the State
remains satisfied that reasonable progress continues to be made in remediating
the site and retains oversight of the process.
In 1995, as part of that process, the Company's consultant completed its
risk assessment report and submitted it to the State of Vermont for review.
The State generally agreed with that assessment but expressed a number of
concerns and directed the Company to collect some additional data. The
Company has addressed almost all of the concerns expressed by the State and
continues to work with the State in a joint effort to develop a mutually
acceptable solution.
The Company selected a consulting/engineering firm to collect the
additional data requested by the State and develop and implement a remediation
plan for the site. That firm has begun work at the site. It has collected
the additional data requested by the State and will use all the data gathered
to date to formulate a comprehensive remediation plan. The additional data
gathered to date has not caused the Company to alter its original estimate of
the likely cost of remediating the site.
PCB, INC. AND OSAGE METALS 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 Potential Responsible
Parties (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 .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 has been identified as a PRP at a third related site to which
PCB Treatment, Inc. shipped capacitors for disposal, Osage Metals. The EPA
has concluded that the Company is a De Minimus party at this Site and has
offered to settle with the Company on this basis. The Company has accepted
the EPA's offer. That settlement, under which the Company pays the EPA about
$3,600, will be finalized in the next 60 days.
PARKER LANDFILL AND THE TRAFTON-HOISINGTON LANDFILL The Company has had no
involvement with these sites for over five years. Additional information on
these sites is available in the Company's Annual Report on Form 10-K.
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.
In 1996, the Company filed a lawsuit in federal court against a number of
insurance companies. In its complaint, the Company alleges that general
liability policies issued by the insurers provide coverage for all expenses
incurred or to be incurred by the Company in conjunction with, among others,
the Cleveland Avenue Property. Settlements have been reached with all but one
defendant, with whom the Company has reached a settlement in principle. Due
to the uncertainties associated with the outcome of this lawsuit related to
the remaining defendant and the actual clean-up costs, the proceeds have been
applied to the environmental reserve.
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 is 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 Vermont Public Service Board's (PSB)
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 recently severely penalized
another VJO member, Green Mountain Power Corporation, 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 current rate case. 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 appeal and associated stay of the rate case significantly delay the
date that new rates would have otherwise taken effect which could now be as
late as early-1999. As a result, the Company's earnings prospects for all of
1998 will continue to be adversely affected.
In an effort to mitigate eroding earnings and cash flow prospects during
the Vermont Supreme Court review process, on June 12, 1998 the Company filed
with the PSB a request for a 10.7% rate increase ($24.7 million of annualized
revenues) effective March 1, 1999. This rate case proceeding overlaps the
6.6 percent rate increase request referenced above.
New Hampshire: On November 26, 1997, Connecticut Valley filed a request
with the New Hampshire Public Utilities Commission (NHPUC) to increase the
Fuel Adjustment Clause (FAC), Purchased Power Cost Adjustment (PPCA) and
short-term energy purchase rates effective on or after January 1, 1998. The
requested increase in rates results 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, the NHPUC 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 (Companies) filed
with the Court for a temporary restraining order to maintain the status quo
ante by staying the NHPUC Order of December 31, 1997 and preventing the NHPUC
from taking any action that (i) compromises cost-based rate making for
Connecticut Valley; (ii) interferes with 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 would designate 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 for the year ended
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 as of December 31, 1997 under SFAS No. 5, "Accounting for
Contingencies," representing Connecticut Valley's estimated loss on power
contracts for the twelve months following December 31, 1997.
On March 20, 1998, the NHPUC issued an order which affirms, clarifies and
modifies 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 addresses all
outstanding motions for rehearings or clarification relative to the policies
or legal positions articulated in the Final Plan and removes 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 has
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.
Also, on April 3, 1998, the Court indicated its 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.
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 suspends all involuntary restructuring efforts for all New Hampshire
utilities until the November hearing. The Company believes that the Court
will convert the preliminary injunction to a permanent injunction.
As a result of these Court orders, Connecticut Valley's 1997 charges
under SFAS No. 5 and SFAS No. 71, 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
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 will
exercise all of its remedies from and after May 5, 1998 in the event that the
violations are 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 has 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 Federal Court's June 5, 1998 Order.
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 has filed a
motion seeking rehearing of the FERC's December 18, 1997 Order. 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.
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 SFAS No. 5 totaling approximately $75.0
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 under SFAS No. 71 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 SFAS No. 5 of
approximately $54.9 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 1998.
The Company has initiated and will continue to work for a negotiated
settlement with parties to the New Hampshire restructuring proceeding and the
NHPUC. The Company cannot predict the ultimate outcome of this matter.
However, an adverse resolution would have a material adverse effect on the
Company's results of operations, cash flows, and ability to obtain capital at
competitive rates.
Note 4 - Investment in Vermont Yankee Nuclear Power Corporation
The Company accounts for its investment in Vermont Yankee using the
equity method. Summarized financial information for Vermont Yankee Nuclear
Power Corporation follows:
Three Months Ended Six Months Ended
June June
1998 1997 1998 1997
---- ---- ---- ----
Operating revenues $57,913 $44,383 $109,083 $84,804
Operating income $ 3,950 $ 3,579 $ 7,710 $ 7,290
Net income $ 1,806 $ 1,748 $ 3,508 $ 3,523
Company's equity in net income $539 $545 $1,049 $1,101
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
June 30, 1998
Earnings Overview
The Company recorded losses available for common stock of $5.9 million
and $2.4 million for the three months ended June 30, 1998 and 1997,
respectively. Losses per share of common stock for these respective periods
were $.52 and $.21. Due to the Company's winter sales peak and higher winter
rates, the Company normally experiences losses in the second and third
quarters when sales are lower and rates are reduced.
Lower second quarter earnings compared to the second quarter 1997
resulted primarily from higher net power costs. Second quarter 1998 power
costs increased due to an extended refueling outage at the Vermont Yankee
Nuclear Power Plant (after-tax impact of $1.6 million) and higher costs under
the Hydro-Quebec power contract (after-tax impact of $1.9 million).
For the six months ended June 30, 1998 earnings available for common
stock were $3.8 million compared to $11.5 million in 1997. Earnings per share
of common stock for these respective periods were $.34 and $1.00.
Included in earnings available for common and earnings per share of
common stock in the first six months of 1998 are the positive impact of
reversing a fourth quarter 1997 charge of $3.6 million (after-tax) and $.31,
respectively, and an after-tax extraordinary credit of $.9 million and $.08,
respectively, at the Company's New Hampshire utility subsidiary, Connecticut
Valley. (See Electric Industry Restructuring - New Hampshire below and Note 1
in Notes to Consolidated Financial Statements for more information.) Other
factors affecting results for 1998 are described in Results of Operations
below.
Earnings available for common stock and earnings per share of common
stock for the first six months of 1997 reflect an after-tax gain of
$1.3 million and $.12, respectively, from a non-recurring asset sale.
Absent the reversal of the fourth quarter 1997 charge of $3.6 million and
the extraordinary credit of $.9 million, 1998's first six months net income
would have been $.3 million, or a loss of $.05 per share of common stock. Net
income for the first six months of 1997 absent the non-recurring asset sale
was $11.2 million, or $.88 per share of common stock.
RESULTS OF OPERATIONS
The major elements of the Consolidated Statement of Income are discussed
below.
Operating Revenues and MWH Sales
A summary of MWH sales and operating revenues for the three and six
months ended June 30, 1998 and 1997 (and the related percentage changes from
1997) is set forth below:
<TABLE>
<CAPTION>
Three Months Ended June 30
------------------------------------------------
Percentage Percentage
MWH Increase Revenues (000's) Increase
1998 1997 (Decrease) 1998 1997 (Decrease)
------- ------- ---------- ------- ------- ----------
<S> <C> <C> <C> <C> <C> <C>
Residential 212,368 217,173 (2.2) $24,428 $24,485 (.2)
Commercial 224,336 216,060 3.8 23,181 22,138 4.7
Industrial 98,530 98,912 (.4) 7,361 7,154 2.9
Other retail 1,763 1,786 (1.3) 486 488 (.4)
------- ------- ------- -------
Total retail sales 536,997 533,931 .6 55,456 54,265 2.2
------- ------- ------- -------
Resale sales:
Firm 451 232 94.4 18 12 50.0
Entitlement 50,744 84,623 (40.0) 5,279 4,612 14.5
Other 144,081 187,203 (23.0) 4,217 4,970 (15.2)
------- ------- ------- -------
Total resale sales 195,276 272,058 (28.2) 9,514 9,594 (.8)
------- ------- ------- -------
Other revenues - - - 1,436 1,583 (9.3)
------- ------- ------- -------
Total sales 732,273 805,989 (9.1) $66,406 $65,442 1.5
======= ======= ======= =======
Six Months Ended June 30
---------------------------------------------------
Percentage Percentage
MWH Increase Revenues (000's) Increase
1998 1997 (Decrease) 1998 1997 (Decrease)
--------- --------- ---------- -------- -------- ----------
<S> <C> <C> <C> <C> <C> <C>
Residential 476,829 492,460 (3.2) $ 59,605 $ 60,288 (1.1)
Commercial 452,768 446,135 1.5 50,643 52,538 (3.6)
Industrial 208,418 214,556 (2.9) 17,456 17,808 (2.0)
Other retail 3,565 3,549 .5 969 959 1.0
--------- --------- -------- --------
Total retail sales 1,141,580 1,156,700 (1.3) 128,673 131,593 (2.2)
--------- --------- -------- --------
Resale sales:
Firm 1,125 497 126.4 37 23 60.9
Entitlement 135,756 195,486 (30.6) 10,263 9,567 7.3
Other 314,170 382,578 (17.9) 8,821 9,777 (9.8)
--------- --------- -------- --------
Total resale sales 451,051 578,561 (22.0) 19,121 19,367 (1.3)
--------- --------- -------- --------
Other revenues - - - 2,570 2,976 (13.6)
--------- --------- -------- --------
Total sales 1,592,631 1,735,261 (8.2) $150,364 $153,936 (2.3)
========= ========= ======== ========
</TABLE>
Retail MWH sales for the second quarter of 1998 were relatively flat
compared to the second quarter of 1997, increasing only about .6%. This
minimal increase resulted in a $1.2 million, or 2.2% increase in retail
revenues.
For the first half of 1998, retail MWH sales decreased 1.3% compared to
the first half of 1997 reflecting moderate temperatures not typical of a
Vermont winter. Retail revenues decreased $2.9 million, or 2.2% compared to
last year. This negative variance during the first half of 1998 is
attributable to a $1.6 million impact of lower MWH sales and $1.3 million
resulting from a modified rate design in bills rendered since April 1, 1997.
The modified rate design, which is revenue neutral on an annual basis,
decreases prices charged during the winter months of December through March
and increases prices during the remaining months of the year. As a result,
lower prices were charged during January through March 1998 than the
comparable 1997 period.
Entitlement MWH sales decreased 40.0% or 33,879 MWH for the second
quarter compared to the same period in 1997. The decrease results primarily
from the scheduled refueling and maintenance outage of the Vermont Yankee
plant, which extended from March 21, 1998 through June 3, 1998, reducing MWH
sales to UNITIL. However, the higher costs of the Company's share of Vermont
Yankee's capacity costs resulting from the refueling and maintenance outage
are passed on to entitlement customers causing an increase in entitlement
revenues of $.7 million, or 14.5%.
For the first half of 1998 entitlement MWH sales decreased 30.6% and
related revenues increased 7.3%, or $.7 million compared to the first half of
1997 for reasons discussed above.
The decrease in other resale sales and revenues for the second quarter
and first half of 1998 resulted primarily from decreased off-system sales and
sales to Nepool partially offset by an increase in short-term system capacity
sales.
The decrease in other revenues for the second quarter and first half of
1998 compared to the 1997 periods results primarily from lower revenues
associated with pole attachment rentals.
Net Purchased Power and Production Fuel Costs
The net cost components of purchased power and production fuel costs for
the three and six months ended June 30, 1998 and 1997 are as follows (dollars
in thousands):
<TABLE>
<CAPTION>
Three Months Ended June 30
1998 1997
Units Amount Units Amount
----- ------ ----- ------
<S> <C> <C> <C> <C>
Purchased and produced:
Capacity (MW) 565 $26,674 474 $23,170
Energy (MWH) 703,024 19,208 778,912 17,135
------- -------
Total purchased power costs 45,882 40,305
Production fuel (MWH) 71,537 394 71,330 425
------- -------
Total purchased power and
production fuel costs 46,276 40,730
Entitlement and other resale sales (MWH) 194,825 9,496 271,826 9,582
------- -------
Net purchased power and production
fuel costs $36,780 $31,148
======= =======
Six Months Ended June 30
1998 1997
Units Amount Units Amount
----- ------ ----- ------
<S> <C> <C> <C> <C>
Purchased and produced:
Capacity (MW) 567 $47,115 499 $44,458
Energy (MWH) 1,539,300 38,473 1,704,976 36,843
------- -------
Total purchased power costs 85,588 81,301
Production fuel (MWH) 146,612 909 132,056 691
------- -------
Total purchased power and
production fuel costs 86,497 81,992
Entitlement and other resale sales (MWH) 449,926 19,084 578,064 19,344
------- -------
Net purchased power and production
fuel costs $67,413 $62,648
======= =======
</TABLE>
Net purchased power and production fuel costs increased $5.6 million, or
18.1% for the second quarter of 1998 compared to the second quarter of 1997
primarily as the result of the extended Vermont Yankee refueling outage and
higher costs under the Hydro-Quebec power contract.
For the first half of 1998, net purchased power and production fuel costs
increased $4.8 million, or 7.6% compared to the first half of 1997. However,
absent the benefit of the 1997 Connecticut Valley reversal discussed above,
net purchased power and production fuel costs increased $10.3 million, or
16.4% for 1998 compared to the same period last year. The $10.3 million
variance is attributable to the Vermont Yankee extended refueling outage and
higher costs under the Hydro-Quebec power contract.
Pursuant to a Vermont Public Service Board (PSB) Accounting Order, first
half 1997 energy costs were reduced by approximately $5.8 million related to a
Hydro-Quebec agreement.
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 1154 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 (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 are approximately $1.3 million on a
pre-tax basis. Such amounts have not been paid or expended at this time. The
Company believes that VELCO will prevail in its efforts to favorably resolve
this matter with PSNH.
NUCLEAR MATTERS
The Company maintains a 1.7303% joint-ownership interest in 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 interests in
Maine Yankee, Yankee Atomic and Vermont Yankee, respectively.
Millstone Unit #3
Millstone Unit #3 (Unit #3) received approval by the NRC commissioners
and NRC staff on June 15, 1998 and June 29, 1998, respectively, to restart
Unit #3 which was shut down on March 30, 1996, due to numerous technical and
non-technical problems. Unit #3 reached full power operation on July 14,
1998. The Company's share of the total incremental operating and maintenance
costs for Unit #3 were about $.9 million for 1997 and about $.3 million for
the first six months of 1998. Incremental replacement power costs for 1998
were about $1.9 million for the six month period that Unit #3 was out of
service.
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.
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.
Yankee Atomic
In 1992, the Yankee Atomic Nuclear power plant was retired from
commercial operation. The Company relied on Yankee Atomic for less than 1.5%
of its system capacity.
Vermont Yankee
The Vermont Yankee Nuclear Power Plant, which provides approximately one-
third of the Company's power supply, began a refueling outage on March 21,
1998 and returned to service on June 3, 1998. The refueling outage extended
twenty-six days beyond the scheduled forty-nine days. The Company incurred
approximately $3.1 million and $6.5 million for replacement energy and
maintenance costs, respectively, of which $7.2 million in total was deferred
consistent with current accounting and ratemaking practices. These deferrals
will be amortized to expense over eighteen months which is the expected in-
service period before Vermont Yankee's next scheduled refueling outage.
The Design Basis Documentation project (Project) initiated by Vermont
Yankee during 1996 is expected to be completed by the end of year 2000. The
Company's 35% share of the total cost for this Project is expected to be about
$5.9 million. Such costs will be deferred by Vermont Yankee and amortized
over the remaining license life of the plant.
Vermont Yankee has received unsolicited expressions of interest to
purchase Vermont Yankee. Discussions between Vermont Yankee and these parties
are continuing.
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 approximately $16.0 million,
$12.0 million and $3.9 million, respectively. These amounts are subject to
ongoing review and revisions and are reflected in the accompanying balance
sheet both as regulatory assets and deferred power contract obligations
(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.
Other Operation
Other operating expenses increased $.7 million and $2.2 million for the
second quarter and first half of 1998 principally due to an increase in
distribution, customer accounts, consulting services and regulatory commission
expenses partially offset by an increase in deferral of conservation and load
management costs (C&LM).
Maintenance
The increase in maintenance expenses of $.9 million for the first half of
1998 compared to the same period in 1997 is attributable to the severe ice
storm in January 1998.
Income Taxes
Federal and state income taxes fluctuate with the level of pre-tax
earnings. The decrease in total income tax expense for the second quarter and
first half of 1998 results primarily from a decrease in pre-tax earnings for
the periods.
Other Income and Deductions
The decrease in other income, net for the 1998 second quarter and first
half results from lower subsidiaries' earnings (see Diversification below) and
a gain of $2.1 million from a non-recurring asset sale in February 1997.
Extraordinary Credit
The 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
discussed above.
Dividends Declared
The decrease in common dividends declared results from an early
declaration made in December 1997 for the quarterly dividend paid on
February 13, 1998.
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 was $6.4 million for the first six months of 1998 versus
$38.5 million for the first six months of 1997. The reduction is due to
reduced cash earnings, the extended refueling outage at the Vermont Yankee
Nuclear Power Plant in the 1998 period, and higher tax payments.
The Company ended the first six months of 1998 with cash and cash
equivalents of $8.8 million, a decrease of $7.7 million from the beginning of
the year. The decrease in cash for the first six months of 1998 was the
result of $6.4 million provided by operating activities, offset by
$8.3 million used for investing activities and $5.8 million used for financing
activities.
Operating Activities - Net income, depreciation and deferred income taxes
and investment tax credits provided $16.2 million. About $9.8 million of cash
was used for working capital needs and other operating activities.
Investing Activities - Construction and plant expenditures consumed
approximately $6.9 million, while $1.4 million was used for C&LM programs and
non-utility investments.
Financing Activities - Dividends paid on common stock were $5.0 million
while preferred dividends were $.5 million. Short-term obligations required
$.4 million and sale of Treasury Stock provided $.1 million.
For related information see the Company's discussion on Financing and
Capitalization below.
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 into affiliate entities that were functionally separate from
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 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, the bill did not
become effective and any efforts to pursue it in the future will require that
it be re-enacted by the Vermont Senate and passed by the House.
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 nor Senate acted on these reforms
which must be reintroduced in the next legislative biennium beginning 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' Electricity Future to lead a new effort to review
the issues of potential restructuring of Vermont's electric industry. Members
of the Working Group include individuals with both business and governmental
experience including a former chairman of the PSB. The purpose of the Working
Group is to determine the best structure for the electric industry in Vermont
so as to achieve the lowest current and long-term electric costs for all
classes of electric consumers. While any recommendations developed through
this effort cannot be implemented without regulatory and/or legislative
enactments, the Governor has expressed that he hopes that the creation of the
Working Group will provide an independent, non-partisan, fact-based analysis
and examination of the issues surrounding electric restructuring and help pave
the way to some type of proposal to pass the 1999 Vermont General Assembly.
The Working Group is charged with presenting a report, with recommendations,
to the Governor and Legislative leaders by December 15, 1998. At this time,
the task force has yet to take any official action.
On July 23, 1998, the PSB announced a series of statewide workshops on
the future of Vermont's regulated network industries including electricity.
The workshops are intended to take a broad, strategic look at these
industries, the services they provide, the problems regulated companies are
facing and ways to reduce the cost of power supply in Vermont and improve
service. Through these workshops, the PSB has promised to invite
participants to present specific proposed actions for utilities, power
marketers, and government to address the problem of increasing power costs in
Vermont. These workshops will begin in late August and will continue through
the fall of 1998.
In order to further prepare Central Vermont Public Service Corporation
for deregulation, on July 24, 1998, the Company filed a petition with the PSB
for permission to create a holding company that would have as subsidiaries the
Company and non-utility subsidiaries-Catamount and SmartEnergy. The Company
believes that a holding company structure will facilitate the Company's
transition to a deregulated electricity market. The proposed holding company
formation must also be approved by Federal regulators, including the
Securities and Exchange Commission and the FERC, and by the Company's
shareholders.
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 affirms, clarifies and
modifies 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 removes 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. Under the wholesale power purchase contract with the
Company, Connecticut Valley may terminate service at the end of a service
year, provided it has given written notice of termination prior to the
beginning of that service year. Claremont alleges 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 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 would designate 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 for the year ended
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 as of December 31, 1997 under SFAS No. 5, "Accounting for
Contingencies," representing Connecticut Valley's estimated loss on power
contracts for the twelve months following December 31, 1997.
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. In compliance with that
order, Connecticut Valley has 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.
Also, on April 3, 1998, the Court indicated that its 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
under SFAS No. 5 and SFAS No. 71 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
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 will
exercise all of its remedies from and after May 5, 1998 in the event that the
violations are 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 has 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 Federal Court's June 5, 1998 Order.
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 has filed a
motion seeking rehearing of the FERC's December 18, 1997 Order. 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.
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 SFAS No. 5 totaling approximately $75.0
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 under SFAS No. 71 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 SFAS No. 5 of
approximately $54.9 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 1998.
For further information on New Hampshire restructuring issues and other
regulatory events in New Hampshire affecting the Company or Connecticut Valley
and the December 1997 charges and reversals of the charges, see the Company's
Form 8-K dated January 12, 1998, January 28, 1998 and April 1, 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 1997 Form 10-K.
The Company has initiated and will continue to work for a negotiated
settlement with parties to the New Hampshire restructuring proceeding and the
NHPUC. The Company cannot predict the ultimate outcome of this matter.
However, an adverse resolution would have a material adverse effect on the
Company's results of operations, cash flows, and ability to obtain capital at
competitive rates.
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 this Quarterly Report on Form 10-Q, the Company believes it
currently complies with the provisions of SFAS No. 71 for its regulated retail
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 $73.0 million on a pre-tax basis as of June 30, 1998. 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, 1997, 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 SFAS No. 5.
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 and ability to obtain capital at
competitive rates. It is possible that stranded cost exposure associated with
SFAS Nos. 5, 71, and 121, before mitigation could exceed the Company's current
total common stock equity.
FINANCING AND CAPITALIZATION
Utility
The level of short-term borrowings fluctuates based on seasonal corporate
needs, the timing of long-term financings and market conditions.
On November 5, 1997 the Company entered into an unsecured $50 million,
364 day committed Revolving Credit and Competitive Advance Facility (Credit
Facility) with a group of banks. With the approval of this facility by the
PSB on April 2, 1998, it became a three-year facility with two one-year
options. However, due to the February 27, 1998 Order issued by the PSB in the
Green Mountain Power Corporation rate proceeding, the banks participating in
this Credit Facility have determined that a material adverse change occurred
in the Company's financial prospects. Such a condition would prevent
borrowings under the Credit Facility. In addition, three letters of credit
with expiry dates between May and December 1999 supporting $16.3 million of
long-term debt of the Company will likely not be rolled over by the issuing
bank, which is the Agent Bank on the $50 million Credit Facility, if such
material adverse change is continuing when those expiry dates occur in 1999.
One letter of credit supporting $5.8 million expires May 1, 1999 and two
letters of credit supporting $10.5 million expire December 1 and 2, 1999.
Negotiations with the banks participating in the Credit Facility have
resulted in an understanding, subject to documentation and regulatory
approval, of modifications to the Credit Facility. Those major changes are:
1) a second mortgage interest in the Company's utility fixed assets;
2) a revised maturity date of June 1, 1999 (the original agreement was to end
in November 2000) with yearly renewals at the banks' discretion; 3) a 25 basis
point increase in interest rates on borrowings; 4) the application of any
proceeds from the issuance of any First Mortgage Bonds during the term of the
Credit Facility to the concurrent repayment of any outstanding loans
thereunder as well as the reduction of the aggregate commitment of the Credit
Facility; and 5) a 25 basis point increase in the cost of the $16.3 million
aggregate amount of letters of credit. During the period in which
documentation and regulatory approval of these changes are being completed,
the banks have agreed to provide up to $10 million on an unsecured basis
through June 1, 1999. At June 30, 1998, the Company had outstanding
approximately $.3 million under this Credit Facility.
The Company has $20.5 million of scheduled first mortgage debt repayments
in December 1998. The Company anticipates those cash requirements will be met
out of borrowings under the Credit Facility. The borrowings under the Credit
Facility are expected to be approximately $25 million by May 1999, just prior
to the June 1, 1999 expiration and repayment date on the Credit Facility. In
addition, the Company will be required to roll over an aggregate of
$16.3 million of letters of credit expiring in May 1999 and December 1999.
The Company's ability to refinance the expected $25.0 million of outstanding
borrowings in May 1999, roll over the approximately $16.3 million of letters
of credit in 1999 and reinstate a new Credit Facility will be largely
dependant on a positive outcome of the Company's pending rate increase
requests.
Connecticut Valley maintained a $.8 million committed line of credit for
its construction program and for other corporate purposes which expired on
May 31, 1998. Connecticut Valley had no outstanding short-term debt at
June 30, 1998. Connecticut Valley is currently renegotiating with Citizens
Bank of New Hampshire to renew this line of credit on a secured basis.
Connecticut Valley has outstanding long-term bank debt of $3.75 million
expiring December 27, 1999, and is negotiating with Citizen's Bank to secure
and extend this facility.
The Company's capital structure ratios as of June 30, 1998 (including
amounts of long-term debt due within one year) consisted of 51.7% common
equity, 7.5% preferred stock and 40.8% long-term debt including capital lease
obligations.
Current credit ratings of the Company's securities as reaffirmed by Duff
& Phelps and Standard & Poor's are as follows:
Duff & Standard
Phelps & Poor's
------ --------
First Mortgage Bonds BBB A-
Corporate Credit Rating BBB
Preferred Stock BBB- BBB-
On January 22, 1998, Standard & Poor's revised its ratings outlook on the
Company to negative from stable stating that the revised outlook reflects the
adverse ruling by the NHPUC related to Connecticut Valley discussed above.
Non-Utility
Catamount, a wholly owned subsidiary of the Company, implemented a credit
facility in July 1996 which provides for up to $8.0 million of letters of
credit and working capital loans. Currently, a $1.2 million letter of credit
is outstanding to support certain of Catamount's obligations in connection
with a debt reserve requirement in the Appomattox Cogeneration project.
Financial obligations of the non-utility wholly owned subsidiaries are
non-recourse to the Company.
C&LM Programs
The primary purpose of these programs is to offset the need for long-term
power supply and delivery resources that are more expensive to purchase or
develop than customer-efficiency programs. Total C&LM expenditures in 1997
were $2.7 million and are expected to be $1.7 million for 1998.
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 two projects under
construction in Thetford and Fort Dunlop, England, and a project under
development in Summersville, West Virginia. Catamount's after-tax earnings
were $.6 million and $.5 million for the second quarter of 1998 and 1997,
respectively, and $1.3 million and $1.0 million for the first half of 1998 and
1997, 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.
SmartEnergy incurred losses of $.5 million and $3 thousand for the second
quarter of 1998 and 1997, respectively, and losses of $.9 million and earnings
of $.04 million for the first half of 1998 and 1997, respectively. These
losses result from activities that will allow SmartEnergy to enter several
niches of the national and international energy market. SmartEnergy has
signed an agreement to manufacture and deliver the SmartDrive dairy vacuum
pump control to domestic and worldwide markets beginning later this year.
Participants in this arrangement are Babson Brothers Company and Asea Brown
Boveri.
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 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
increasing cost of providing service. Approximately $14.3 million or 92.9% of
the rate increase request is 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.
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 overlaps
the 6.6% rate increase request referenced above.
New Hampshire: 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
results from higher forecast energy and capacity charges on power Connecticut
Valley purchases from the Company plus removal of credit effective during 1997
to refund overcollections from 1996.
In an order dated December 31, 1997, the NHPUC 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.
For additional information on Vermont and New Hampshire rate and
regulatory matters see Electric Industry Restructuring discussed above and
Note 3 to the Consolidated Financial Statements.
Year 2000 Information Systems Modifications
The Company has assessed the impact of the year 2000 issue on its
computer systems and applications. During 1997, the Company incurred costs of
approximately $.1 million and estimates that about $2.5 million will be
incurred in 1998 and $.2 million will be incurred in 1999 to modify its
existing computer systems and applications which are expected to be completed
during the second quarter of 1999. During the first quarter of 1998, the
Company requested an accounting order from the PSB to defer these operating
and maintenance costs. By letter dated June 10, 1998, the PSB declined to
issue the requested accounting order, and directed the Company to recognize
the Year 2000 costs in the period in which they occurred. The PSB also opened
a generic proceeding into Year 2000 readiness and compliance costs, including
the appropriate accounting treatment for those costs, for all Vermont
utilities.
On June 23, 1998, the Company asked the PSB to reconsider its decision
with respect to the Company. On July 21, 1998, members of the PSB met with
the Company's representatives and of the Vermont Department of Public Service
to discuss the issues involved. As a result, the letter signed by the PSB
denying the accounting treatment requested by the Company was thereby
rescinded. The PSB will reconsider the issuance of an accounting order, and
the Company anticipates that a final determination by the PSB will be issued
by the end of the third quarter of 1998.
The Company believes that based on the current regulatory process, these
costs will be recovered through the regulatory process and therefore they do
not represent the potential for a material adverse effect on its financial
position or results of operations.
Management Audit
On April 17, 1997, the PSB ordered an independent forward-looking
analysis of three of the Company's management policies and practices focusing
on three areas: 1) Transmission of information to the Company's Board of
Directors by management. 2) Cost-benefit analyses for major corporate
decisions. 3) Implementation of the Company's ethics and conflict of interest
policy. An independent analysis on these areas began during the first quarter
of 1998 and a final report is expected during the third quarter of 1998.
New Accounting Pronouncement
In April 1998, the American Institute of Certified Public Accountants
issued Statement of Position 98-5, "Reporting on the Costs of Start-up
Activities" (SOP 98-5). SOP 98-5 provides guidance on the financial reporting
of start-up costs and organization costs. It requires costs of start-up
activities and organization costs to be expensed as incurred and is effective
for financial statements for fiscal years beginning after December 15, 1998.
The Company continues to evaluate the impact that the adoption of SOP 98-5
will have on the Company's financial position or results of operations.
Proposed Formation of Holding Company
In order to further prepare Central Vermont Public Service Corporation
for deregulation, on July 24, 1998, the Company filed a petition with the PSB
for permission to create a holding company that would have as subsidiaries the
Company and non-utility subsidiaries-Catamount and SmartEnergy. The Company
believes that a holding company structure will facilitate the Company's
transition to a deregulated electricity market. The proposed holding company
formation must also be approved by Federal regulators, including the
Securities and Exchange Commission and the FERC, and by the holders of the
Company's shareholders.
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 July 29, 1996, the Company filed a Declaratory Judgment action in
the United States District Court for the District of Vermont. The Complaint
names as defendants a number of insurance companies that issued policies to
the Company dating from the mid 1940s to the late 1980s. The Company asserts
that policies issued by defendants provide coverage for all defense and
remediation costs associated with the Cleveland Avenue property, the
Bennington Landfill site and the North Clarendon site. With the exception of
the North Clarendon site, no further remediation is anticipated. See Note 2
to the Consolidated Financial Statements for related disclosures.
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, 3 and 4.
None.
Item 5. Other Information.
(a) Effective July 20, 1998, Delano E. Lewis was elected to the
Company's Board of Directors to replace Preston Leete Smith,
who chose to retire early.
(b) Date for Submission of Stockholder Proposals for 1999 Annual
Meeting of Stockholders -
A stockholder desiring to present a proposal at the Company's
1999 Annual Stockholders' Meeting and to have such proposal
considered for inclusion in the proxy materials for such
meeting should submit such proposal addressed to the
Secretary, Joseph M. Kraus, no later than November 21, 1998.
Any such proposal must comply with Rule 14a-8 of
Regulation 14A of the proxy rules of the Securities
and Exchange Commission and will be omitted from or included
in the proxy material at the discretion of the Board of
Directors of the Company in accordance with such applicable
laws and regulations.
Item 6. Exhibits and Reports on Form 8-K.
(a) List of Exhibits
10. Material Contracts
* 10.83.1 First Amendment to Credit Agreement Dated as of
April 15, 1998
* 10.83.2 Second Amendment to Credit Agreement Dated as of
June 2, 1998
27. Financial Date Schedule.
(b) Item 5. Other Events, Form 8-K dated April 1, 1998 was filed
on April 30, 1998 re:
(1) Preliminary Injunction Stays New Hampshire Rate Order
(2) Vermont Retail Rate Case
(3) Revolving Credit and Competitive Advance Facility
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
(Registrant)
By Francis J. Boyle
__________________________________________________
Francis J. Boyle, Senior Vice President, Principal
Financial Officer and Treasurer
By James M. Pennington
_______________________________________________
James M. Pennington, Vice President, Controller
and Principal Accounting Officer
Dated August 7, 1998
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This Financial Data Schedule contains summary financial information extracted
from the Consolidated Financial Statements included herein and is qualified in
its entirety by reference to such financial statements (dollars in thousands,
except per share amounts).
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> JUN-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 319,653
<OTHER-PROPERTY-AND-INVEST> 64,164
<TOTAL-CURRENT-ASSETS> 53,430
<TOTAL-DEFERRED-CHARGES> 78,303
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 515,550
<COMMON> 66,105
<CAPITAL-SURPLUS-PAID-IN> 45,307
<RETAINED-EARNINGS> 74,646
<TOTAL-COMMON-STOCKHOLDERS-EQ> 186,058
18,000
8,054
<LONG-TERM-DEBT-NET> 108,839
<SHORT-TERM-NOTES> 250
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 20,521
1,000
<CAPITAL-LEASE-OBLIGATIONS> 16,682
<LEASES-CURRENT> 1,094
<OTHER-ITEMS-CAPITAL-AND-LIAB> 155,052
<TOT-CAPITALIZATION-AND-LIAB> 515,550
<GROSS-OPERATING-REVENUE> 150,364
<INCOME-TAX-EXPENSE> 2,013
<OTHER-OPERATING-EXPENSES> 141,751
<TOTAL-OPERATING-EXPENSES> 143,764
<OPERATING-INCOME-LOSS> 6,600
<OTHER-INCOME-NET> 2,598
<INCOME-BEFORE-INTEREST-EXPEN> 9,198
<TOTAL-INTEREST-EXPENSE> 5,259
<NET-INCOME> 4,812
973
<EARNINGS-AVAILABLE-FOR-COMM> 3,839
<COMMON-STOCK-DIVIDENDS> 5,034
<TOTAL-INTEREST-ON-BONDS> 4,020
<CASH-FLOW-OPERATIONS> 6,397
<EPS-PRIMARY> .34
<EPS-DILUTED> .34
</TABLE>
EXHIBIT 10.83.1
---------------
FIRST AMENDMENT TO
CREDIT AGREEMENT
FIRST AMENDMENT, dated as of April 15, 1998 (this
"Amendment"), to the Credit Agreement referred to below by
and among CENTRAL VERMONT PUBLIC SERVICE CORPORATION, a
Vermont corporation ("Borrower"), each of the lenders that
is a signatory to the Credit Agreement or which, pursuant to
Section 10.6 thereof shall become a "Lender" thereunder (the
"Lenders"), FLEET NATIONAL BANK, as syndication agent (the
"Syndication Agent") and TORONTO DOMINION (TEXAS), INC., as
agent for the Lenders hereunder (the "Agent"; Lenders,
Syndication Agent and Agent are sometimes collectively
referred to herein as the "Lending Group").
WITNESSETH
WHEREAS, Borrower and Lending Group are parties to that
certain Credit Agreement, dated as of November 5, 1997 (as
amended, supplemented or otherwise modified from time to
time, the "Credit Agreement"); and
WHEREAS, Borrower and Lending Group have agreed to amend the
Credit Agreement in the manner, and on the terms and
conditions, provided for herein in order to clarify certain
ambiguities therein to better reflect the intentions of the
parties.
NOW THEREFORE, in consideration of the premises and for
other good and valuable consideration, the receipt, adequacy
and sufficiency of which are hereby acknowledged, Borrower
and Lending Group hereby agree as follows:
1. Definitions. Capitalized terms not otherwise defined
herein shall have the meanings ascribed to them in the
Credit Agreement.
2. Amendment to Section 5.2 of the Credit Agreement.
Section 5.2 of the Credit Agreement is hereby amended by
adding a new subsection (e) immediately following subsection
(d) thereto to read as follows:
"(e) No Material Adverse Effect. No fact has become known
to the Borrower which has had or in the reasonable judgment
of the Borrower may in the future have a materially adverse
effect on the business, operations, assets, liabilities,
financial condition, results of operations or business
prospects of the Borrower or on its ability to perform its
obligations under this Agreement or the Existing Letter of
Credit Agreements since the Closing Date."
3. No Other Amendments. Except as expressly amended,
herein, each of the Credit Agreement and the other Loan
Documents shall be unmodified and shall continue to be in
full force and effect in accordance with its terms.
4. Effectiveness. This Amendment shall become effective as
of the date hereof.
5. GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY, AND
INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW
YORK.
6. Counterparts. This Amendment may be executed by the
parties hereto on any number of separate counterparts and
all of said counterparts taken together shall be deemed to
constitute one and the same instrument.
(SIGNATURE PAGE FOLLOWS)
IN WITNESS WHEREOF, the parties hereto have caused this
Amendment to be duly executed and delivered as of the day
and year first above written.
Borrower:
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
By: /s/ Francis J. Boyle
Francis J. Boyle
Senior Vice President, Chief Financial Officer and Treasurer
Agent:
TORONTO DOMINION (TEXAS), INC.
By: /s/ Jano Mott
Jano Mott
Vice President
Lenders:
TORONTO DOMINION (NEW YORK), INC.
By: /s/ Debbie A. Greene
Debbie A. Greene
Vice President
BANKBOSTON, N.A.
By: /s/ Virginia Ryan
Virginia Ryan
Vice President
FLEET NATIONAL BANK
By: /s/ Robert D. Lanigan
Robert D. Lanigan
Director
CITIZENS BANK NEW HAMPSHIRE
By: /s/ Vernon T. Studer
Vernon T. Studer
Vice President
EXHIBIT 10.83.2
---------------
SECOND AMENDMENT TO
CREDIT AGREEMENT
SECOND AMENDMENT, dated as of June 2, 1998 (this
"Amendment"), to the Credit Agreement referred to below by
and among CENTRAL VERMONT PUBLIC SERVICE CORPORATION, a
Vermont corporation ("Borrower"), each of the lenders that
is a signatory to the Credit Agreement or which, pursuant to
Section 10.6 thereof shall become a "Lender" thereunder (the
"Lenders"), FLEET NATIONAL BANK, as syndication agent (the
"Syndication Agent") and TORONTO DOMINION (TEXAS), INC., as
agent for the Lenders hereunder (the "Agent"; Lenders,
Syndication Agent and Agent are sometimes collectively
referred to herein as the "Lending Group").
WITNESSETH
WHEREAS, the Borrower and the Lending Group are parties to
that certain Credit Agreement, dated as of November 5, 1997
(as amended, supplemented or otherwise modified from time to
time, the "Credit Agreement"); and
WHEREAS, the Borrower and the Lending Group have agreed to
amend the Credit Agreement in the manner, and on the terms
and conditions, provided for herein.
NOW THEREFORE, in consideration of the premises and for
other good and valuable consideration, the receipt, adequacy
and sufficiency of which are hereby acknowledged, the
Borrower and the Lending Group hereby agree as follows:
1. Definitions. Capitalized terms not otherwise defined
herein shall have the meanings ascribed to them in the
Credit Agreement.
2. Amendments to the Credit Agreement.
(a) Section 1.1 of the Credit Agreement is hereby amended
by (1) inserting the text "0.25% plus" immediately prior to
the text "the greater of" appearing in the first sentence of
the definition of "ABR".
(b) Section 1.1 of the Credit Agreement is hereby further
amended by deleting in its entirety the table appearing in
the definition of "Applicable Margin" and inserting in lieu
thereof the following new table and text:
"Debt Rating Applicable Margin
BB (or lower) 1.00%
BB+ 0.75%
BBB- 0.55%
BBB 0.475%
BBB+ 0.435%
A- 0.40%
A (or higher) 0.375%"
(c) Section 1.1 of the Credit Agreement is hereby further
amended by deleting in its entirety the definition of
"Maturity Date" appearing therein and inserting in lieu
thereof the following new definition:
"Maturity Date" shall mean June 1, 1999, unless extended as
provided in Section 2.6(b), in which case the Maturity Date
shall mean June 1, 2000, June 1, 2001, June 1, 2002 or
November 5, 2002, as the case may be.
(d) Section 1.1 of the Credit Agreement is hereby further
amended by inserting in appropriate alphabetical order the
following new definition:
"Aggregate Commitment Increase Date" means the date on which
all of the following conditions are satisfied:
(i) the Loans and all other obligations of the Borrower to
the Agent and the Lenders pursuant to the Loan Documents
shall have been secured by a duly perfected second priority
security interest in all the properties and other assets
that secure the First Mortgage Bonds (the "Collateral"),
subject only to the security interest in favor of the
holders of the First Mortgage Bonds, and such documentation
as shall be reasonably required by the Agent and the Lenders
to evidence the granting of such second priority security
interest (the "Security Documentation") shall have been duly
executed and delivered by the parties thereto;
(ii) the parties hereto shall have executed an amendment to
the Credit Agreement (the "Amendment"), in form and
substance satisfactory to the Agent and the Lenders,
reflecting the provisions set forth in the Summary of Terms
and Conditions attached hereto as Schedule 2 (including,
without limitation, the granting of such second priority
security interest in the Collateral), and such amendment
shall be in full force and effect;
(iii) the Borrower shall have received the approval of the
Vermont Public Service Board and the approval of or waiver
by any other state regulatory body with jurisdiction, in
each case required for (x) (A) the 0.25% increase in the ABR
and the Applicable Margin and (B) the extensions of the
Maturity Date, in each case effected by the Second Amendment
to this Agreement and (y) the grant of the security interest
to the Lenders in the Collateral;
(iv) the Agent shall have received evidence that all other
actions necessary or, in the opinion of the Agent and its
counsel, desirable to perfect and protect the security
interest purported to be created by the Security
Documentation have been taken; and
(v) the Agent shall have received such legal opinions and
other certificates as the Agent may reasonably request
relating to the Security Documentation, the security
interest taken in the Collateral and the Amendment.
"Second Amendment Consent Date" shall mean the date on which
the Borrower shall have received the approval of the Vermont
Public Service Board and the approval of or waiver by any
other state regulatory body with jurisdiction, in each case
required for (x) the 0.25% increase in the ABR and the
Applicable Margin and (y) the extensions of the Maturity
Date, in each case effected by the Second Amendment to this
Agreement.
(e) Section 2.3(a) of the Credit Agreement is hereby
amended by inserting immediately after the table appearing
therein the following new text:
"Notwithstanding anything to the contrary set forth herein,
solely for purposes of calculating the above facility fee,
the Aggregate Commitment Increase Date shall be deemed to
have occurred."
(f) Section 2.3(c) of the Credit Agreement is hereby
amended by deleting the word "If" appearing at the beginning
of such Section, and inserting in lieu thereof the new text
"At any time on and after the Aggregate Commitment Increase
Date, if".
(g) Section 2.6 of the Credit Agreement is hereby amended
by deleting in their entirety paragraphs (b) and (c)
thereof, and inserting in lieu thereof the following new
paragraph (b):
"(b) So long as (i) no Default or Event of Default has
occurred and is continuing, (ii) there has been no material
adverse change in the business or financial condition of the
Borrower since the date of the Second Amendment to this
Agreement, (iii) the Second Amendment Consent Date shall
have occurred and (iv) the Borrower has delivered to the
Agent such evidence thereof as the Agent may reasonably
request, then upon June 1, 1999 and each of the first,
second and third anniversaries thereof, the Borrower may, at
its option, subject to the approval of all of the Lenders,
extend the Maturity Date for an additional one-year period,
provided that in the case of any such extension of the
Maturity Date beyond June 1, 2002 such Maturity Date shall
be extended for a period ending on November 5, 2002."
(h) Section 5.2(e) of the Credit Agreement is hereby
amended by deleting the text "the Closing Date" appearing
therein and inserting the text "(x) the date of the Second
Amendment to this Agreement" in lieu thereof.
(i) The Credit Agreement is hereby further amended by
deleting in its entirety Schedule 1 attached thereto and
inserting in lieu thereof Schedule 1 attached hereto.
3. No Other Amendments. Except as expressly amended,
herein, each of the Credit Agreement and the other Loan
Documents shall be unmodified and shall continue to be in
full force and effect in accordance with its terms.
4. Effectiveness. This Amendment shall become effective as
of the date hereof.
5. GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY, AND
INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW
YORK.
6. Counterparts. This Amendment may be executed by the
parties hereto on any number of separate counterparts and
all of said counterparts taken together shall be deemed to
constitute one and the same instrument.
(SIGNATURE PAGE FOLLOWS)
IN WITNESS WHEREOF, the parties hereto have caused this
Amendment to be duly executed and delivered as of the day
and year first above written.
Borrower:
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
By: /s/ Francis J. Boyle
Francis J. Boyle
Sr. Vice President, CFO, Treasurer
Agent:
TORONTO DOMINION (TEXAS), INC.
By: /s/ Jano Mott
Jano Mott
Vice President
Lenders:
TORONTO DOMINION (NEW YORK), INC.
By: /s/ Jorge A. Garcia
Jorge A. Garcia
Vice President
BANKBOSTON, N.A.
By: /s/ Virginia Ryan
Virginia Ryan
Vice President
FLEET NATIONAL BANK
By: /s/ Robert D. Lanigan
Robert D. Lanigan
Director
CITIZENS BANK NEW HAMPSHIRE
By: /s/ Vernon T. Studer
Vernon T. Studer
Vice President
</PAGE>
<PAGE>
Schedule 1
COMMITMENTS OF THE LENDERS
At any time during the period ending on the Aggregate
Commitment Increase Date:
Lender: Toronto Dominion (New York), Inc.
Address: 909 Fanin
Houston, TX 77010
Commitment: $3,000,000
Commitment Percentage: 30%
Lender: BankBoston
Address: 100 Federal Street
Boston, MA 02110
Commitment: $2,000,000
Commitment Percentage: 20%
Lender: Citizens Bank
Address: 20 West Park Street
Lebanon, NH 03766
Commitment: $1,500,000
Commitment Percentage: 15%
Lender: Fleet National Bank
Address: One Federal Street
Boston, MA 02110
Commitment: $3,500,000
Commitment Percentage: 35%
Total Commitment: $10,000,000
Total Commitment Percentage: 100%
At any time on and after the Aggregate Commitment Increase
Date:
Lender: Toronto Dominion (New York), Inc.
Address: 909 Fanin
Houston, TX 77010
Commitment: $15,000,000
Commitment Percentage: 30%
Lender: BankBoston
Address: 100 Federal Street
Boston, MA 02110
Commitment: $10,000,000
Commitment Percentage: 20%
Lender: Citizens Bank
Address: 20 West Park Street
Lebanon, NH 03766
Commitment: $7,500,000
Commitment Percentage: 15%
Lender: Fleet National Bank
Address: One Federal Street
Boston, MA 02110
Commitment: $17,500,000
Commitment Percentage: 35%
Total Commitment: $50,000,000
Total Commitment Percentage: 100%
</PAGE>
<PAGE>
Schedule 2
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CREDIT FACILITIES
Summary of Terms and Conditions
May 20, 1998
Reference is made to (i) that certain Credit Agreement,
dated as of November 5, 1997 (as amended by the First
Amendment thereto, dated as of April 15, 1998, the "Credit
Agreement" capitalized terms defined therein being used
herein as therein defined) among Central Vermont Public
Service Corporation (the "Company"), the lenders from time
to time party thereto (the "Lenders") and Toronto Dominion
(Texas), Inc., as agent for the Lenders (in such capacity,
the "Agent") and (ii) (A) the Amended and Restated
Reimbursement Agreement, dated as of September 24, 1992, as
amended, between the Company and The Toronto-Dominion Bank,
through its Houston Office (the "Bank"), (B) the
Reimbursement Agreement, dated as of April 29, 1993, as
amended, between the Company and Central Vermont Public
Service Corporation - East Barnet Hydroelectric, Inc.,
together with the Company's guaranty related thereto, and
(C) the Letter of Credit and Reimbursement Agreement, dated
as of November 1, 1994, as amended, between the Company and
the Bank (collectively, the "Reimbursement Agreements").
The following represents an outline of proposed
modifications to the Credit Agreement (the "Amendment") and
to each of the Reimbursement Agreements (collectively, the
"Reimbursement Agreement Amendments") in connection with,
among other things, the Company providing collateral to
secure the Company's obligations under the Loan Documents
and the Reimbursement Agreements. The following is for
discussion purposes only and is not a commitment on the part
of the Agent or any Lender to modify the Credit Agreement or
any other Loan Document, or on the part of the Bank to
modify the Reimbursement Agreements or to waive any
provision thereof or to take or omit to take any action and
any such agreement on the part of the Agent, any Lender or
the Bank would be in a separate written instrument signed by
the Agent, each Lender and the Bank, as the case may be,
following satisfactory completion of their due diligence,
internal review and approval process. Without limiting the
foregoing, it is currently contemplated that except as set
forth below the Credit Agreement, the other Loan Documents
and the Reimbursement Agreements will remain substantially
unchanged.
I. AMENDMENT GENERAL PROVISIONS
Maturity: The Maturity Date shall be amended to June 1,
1999. Subject to the unanimous approval of all of the
Lenders in their sole discretion and of the Company, the
Maturity Date may be extended for one year on each
anniversary thereof.
Interest Rate: After giving effect to the Amendment, each
Revolving Loan shall bear interest at a rate .25% higher
than would otherwise be applicable absent the Amendment.
Collateral: The Loans and all other obligations of the
Company to the Agent and the Lenders pursuant to the Loan
Documents shall be secured by a perfected second priority
security interest in all of the properties and other assets
that secure the First Mortgage Bonds (the "Collateral"),
subject only to the security interest in favor of the
holders of the First Mortgage Bonds (the "Bondholders").
The Company will grant such second priority security
interest in favor of the Agent on behalf of the Lenders
pursuant to documentation (the "Security Documentation")
reasonably satisfactory to the Lenders. Without limiting
the foregoing, it is currently contemplated that such
documentation will be substantively the same as the
Indenture of Mortgage pursuant to which the First Mortgage
Bonds have been issued, as supplemented from time to time
(the "First Mortgage Indenture"), including with respect to
additional representations, warranties and covenants, except
for changes necessitated by the relative priorities of the
security interests granted in favor of the Bondholders and
those granted in favor of the Lenders and other changes
mutually agreed to by the Company and the Lenders; provided,
however, that for purposes of the issuance of additional
indebtedness and the release of property from the lien
granted under the Security Documentation, the Company shall
not have breached any of its warranties or covenants to the
Lenders if it has satisfied the applicable requirements
under the First Mortgage Indenture and, provided, further,
that if the Company has satisfied the requirement under the
First Mortgage Indenture to release property thereunder, the
Agent shall release such property from the lien granted
under the Security Documentation upon such release under the
First Mortgage Indenture; and, provided, further, that the
Company shall not be required to satisfy specific issuance
tests with respect to the incurrence of additional
indebtedness with each borrowing under the Credit Agreement
as amended by the Amendments.
Unsecured Borrowing: Until such time as the Company shall
have received the approval of the Vermont Public Service
Board required for the grant of the security interest to the
Lenders as described under "Collateral" above, the Company
shall be entitled to borrow on an unsecured basis, in one or
more borrowings an aggregate amount at any one time
outstanding not in excess of $10,000,000, which borrowings
shall accrue interest at the rate provided under the Credit
Agreement, as amended by the provision referred to under
"Interest Rate" above. If the accrual of interest at such
higher rates is subject to the approval of the Vermont
Public Service Board, such borrowings shall accrue interest
at the current rates and the Company shall pay a fee to the
Lenders at the time such approval is obtained equal to the
increased compensation the Lenders would have received had
such borrowings borne interest at the higher rates.
Mandatory Commitment
Reductions and Prepayments
Upon Future Bond
Financings: If at any time, the Company issues any First
Mortgage Bonds after the date hereof, the net proceeds
thereof will be applied to the repayment of any outstanding
Loans. In addition, the Aggregate Commitment shall be
reduced by the amount of such net proceeds.
II. CERTAIN CONDITIONS TO AMENDMENT
The effectiveness of the Amendment will be conditioned upon,
among other things, satisfaction of the following conditions
precedent:
1. The Company, the Agent and each Lender shall have
executed and delivered the Amendment, and the applicable
parties shall have executed and delivered the Security
Documentation and all such other instruments and agreements
related thereto (all such documentation, including the
Amendment, collectively the "Amendment Documentation") in
each case in form and substance satisfactory to the Lenders.
2. All governmental and third party approvals (including
the approval of the Vermont Public Service Board) necessary
or advisable in connection with the execution, delivery and
performance of the Amendment Documentation, including the
granting of the security interest in the Collateral shall
have been obtained and be in full force and effect.
3. No Default or Event of Default shall have occurred and
be continuing after giving effect to the execution and
delivery of the Amendment Documentation.
4. All filings and other actions required to perfect the
second priority security interest in favor of the Agent on
behalf of the Lenders in all the Collateral shall have been
duly made or taken, and the Collateral shall be free and
clear of all other liens other than those in favor of the
Bondholders and other customary exceptions to be agreed
upon.
5. All representations and warranties set forth in the
Credit Agreement shall be true and correct in all material
respects with the same effect as though made at the time of
the execution and delivery by the Company of the Amendment
Documentation.
6. The Lenders shall have received such legal opinions,
corporate documents and other instruments as are customary
for transactions of this type or as the Agent may reasonably
request, in each case in form and substance satisfactory to
the Agent. Such opinions shall include, without limitation,
an opinion of counsel to the Company concluding that the
execution and delivery of the Amendment Documentation will
not conflict with, or otherwise result in a breach of any of
the terms of, the First Mortgage Indenture.
III REIMBURSEMENT AGREEMENT AMENDMENTS
Facility Fee and
Interest Rates: After giving effect to the Reimbursement
Agreement Amendments, the Facility Fees and interest rates
as and to the extent payable payable under each of the
Reimbursement Agreements shall be increased by .25%.
Collateral: The obligations of the Company to the Bank
under the Reimbursement Agreements shall be secured pari
passu with the Loans and other obligations of the Company to
the Agent and the Lenders as described under "Collateral" in
I above. The Agent will act as collateral agent for itself
and the Lenders, as well as the Bank.
Conditions: The effectiveness of the Reimbursement
Agreement Amendments will be subject to conditions that are
comparable to those listed in II above.
