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, 2000
TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to _______
Commission file number 1-8222
Central Vermont Public Service Corporation
(Exact name of registrant as specified in its charter)
Incorporated in Vermont 03-0111290
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
77 Grove Street, Rutland, Vermont 05701
(Address of principal executive offices) (Zip Code)
802-773-2711
(Registrant's telephone number, including area code)
(Former name, former address and former fiscal year, if changed since last
report)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date. As of July 31, 2000 there
were outstanding 11,505,730 shares of Common Stock, $6 Par Value.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q
Table of Contents
Page
PART I. FINANCIAL INFORMATION
<PAGE>
Item 1. Financial Statements
Consolidated Statement of Income and Retained Earnings
for the six months ended June 30, 2000 and 1999 3
Consolidated Balance Sheet as of June 30, 2000 and
December 31, 1999 4
Consolidated Statement of Cash Flows for the six
months ended June 30, 2000 and 1999 5
Notes to Consolidated Financial Statements 6-17
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 18-35
PART II. OTHER INFORMATION 36
SIGNATURE 37
<PAGE>
<TABLE>
<CAPTION>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENT OF INCOME AND RETAINED EARNINGS
(Dollars in thousands, except per share amounts)
(Unaudited)
Three Months Ended Six Months Ended
June 30 June 30
2000 1999 2000 1999
<S> <C> <C> <C> <C>
Operating Revenues $73,867 $93,139 $173,816 $191,781
Operating Expenses
Operation
Purchased power 44,432 62,899 98,008 112,934
Production and transmission 6,811 5,761 13,314 10,760
Other operation 10,181 11,195 20,863 23,234
Maintenance 3,408 4,156 6,233 7,040
Depreciation 4,223 4,212 8,506 8,397
Other taxes, principally property taxes 2,818 2,815 5,843 5,902
Taxes on income (83) 238 6,408 7,795
------- ------- -------- --------
Total operating expenses 71,790 91,276 159,175 176,062
------- ------- -------- --------
Operating Income 2,077 1,863 14,641 15,719
------- ------- -------- --------
Other Income and Deductions
Equity in earnings of affiliates 731 760 1,477 1,505
Other income net 1,623 326 (1,414) 1,290
Benefit (provision) for income taxes (440) (17) 823 (262)
------- ------- -------- --------
Total other income and deductions, net 1,914 1,069 886 2,533
------- ------- -------- --------
Total Operating and Other Income 3,991 2,932 15,527 18,252
Net Interest Expense 3,717 2,516 7,294 5,106
------- ------- -------- --------
Net Income (Loss) 274 416 8,233 13,146
Retained Earnings at Beginning of Period 79,885 80,013 72,371 67,748
------- ------- -------- --------
Retained Earnings before Dividends 80,159 80,429 80,604 80,894
Cash Dividends Declared
Preferred stock 890 466 1,335 931
Common stock 5,049 2,527 5,049 2,527
------- ------- -------- --------
Total dividends declared 5,939 2,993 6,384 3,458
------- ------- -------- --------
Other Adjustments (168) - (168) -
------- ------- -------- --------
Retained Earnings at End of Period $74,052 $77,436 $ 74,052 $ 77,436
======= ======= ======== ========
Earnings (Losses) Available For $ (171) $ (50) $ 7,343 $ 12,215
Common Stock
Average Shares of Common Stock
Outstanding 11,476,556 11,462,417 11,471,680 11,461,778
Earnings (Losses) Per Basic and
Diluted Share of Common Stock $ (.01) $ .00 $ .64 $ 1.07
======= ======= ======== ========
Dividends Paid Per Share of Common Stock $ .22 $ .22 $ .44 $ .44
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION> CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED BALANCE SHEET
(Dollars in thousands) June 30 December 31
2000 1999
<S> <C> <C>
Assets
Utility Plant, at original cost $477,615 $475,845
Less accumulated depreciation 181,054 173,605
-------- --------
296,561 302,240
Construction work in progress 13,572 11,315
Nuclear fuel, net 888 1,177
-------- --------
Net utility plant 311,021 314,732
======== ========
Investments and Other Assets
Investments in affiliates, at equity 25,575 25,501
Non-utility investments 43,493 45,269
Non-utility property, less accumulated depreciation 2,326 2,513
-------- --------
Total investments and other assets 71,394 73,283
-------- --------
Current Assets
Cash and cash equivalents 54,012 35,461
Special deposits 114 113
Accounts receivable, less allowance for uncollectible
accounts ($1,684 in 2000 and $1,595 in 1999) 21,612 38,381
Unbilled revenues 13,697 20,605
Materials and supplies, at average cost 3,578 3,126
Prepayments 2,845 1,964
Other current assets 6,115 6,510
-------- --------
Total current assets 101,973 106,160
-------- --------
Regulatory Assets 56,356 62,808
-------- --------
Other Deferred Charges 7,075 6,976
-------- --------
Total Assets $547,819 $563,959
======== ========
Capitalization and Liabilities
Capitalization
Common stock, $6 par value, authorized
19,000,000 shares; outstanding 11,785,848 shares $ 70,715 $ 70,715
Other paid-in capital 45,351 45,340
Accumulated other comprehensive income (246) (246)
Treasury stock (303,818 shares and 319,043 shares,
respectively, at cost) (3,963) (4,159)
Retained earnings 74,052 72,371
-------- --------
Total common stock equity 185,909 184,021
Preferred and preference stock 8,054 8,054
Preferred stock with sinking fund requirements 16,000 17,000
Long-term debt 156,058 155,251
Capital lease obligations 14,570 15,060
-------- --------
Total capitalization 380,591 379,386
-------- --------
Current Liabilities
Current portion of long-term debt and preferred stock 17,691 16,688
Accounts payable 5,063 14,843
Accounts payable - affiliates 10,970 12,311
Accrued income taxes - 675
Dividends declared 2,971 2,523
Nuclear decommissioning costs 2,634 3,457
Disallowed purchased power costs 2,859 2,859
Other current liabilities 17,483 18,823
-------- --------
Total current liabilities 59,671 72,179
-------- --------
Deferred Credits
Deferred income taxes 44,025 48,631
Deferred investment tax credits 6,244 6,440
Nuclear decommissioning costs 17,377 18,548
Other deferred credits 39,911 38,775
-------- --------
Total deferred credits 107,557 112,394
-------- --------
Total Capitalization and Liabilities $547,819 $563,959
======== ========
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)
(Unaudited)
Six Months Ended
June 30
2000 1999
<S> <C> <C>
Cash Flows Provided (Used) By
Operating Activities
Net income $ 8,233 $13,146
Adjustments to reconcile net income to net cash
provided by operating activities
Equity in earnings of affiliates (1,477) (1,505)
Dividends received from affiliates 1,914 1,697
Equity in (earnings) losses of non-utility
investments 2,028 (1,520)
Distribution of earnings from non-utility
investments 2,793 2,758
Depreciation 8,506 8,397
Deferred income taxes and investment tax credits (4,151) 1,499
Net deferral and amortization of nuclear refueling
replacement energy and maintenance costs 3,038 1,377
Amortization of conservation and load management
Costs 2,610 3,304
Amortization of capital leases 544 541
Decrease in accounts receivable and unbilled
revenues 23,389 1,400
Increase (decrease) in accounts payable (10,460) 2,514
Decrease in accrued income taxes (1,682) (1,657)
Change in other working capital items (889) (122)
Other, net (78) 1,070
Net cash provided by operating activities 34,318 32,899
Investing Activities
Construction and plant expenditures (6,113) (5,817)
Conservation & load management expenditures (606) (1,547)
Return of capital 93 93
Non-utility investments (3,507) (1,601)
Other investments, net 9 (10)
Net cash used for investing activities (10,124) (8,882)
Financing Activities
Short-term debt, net 2 (8,750)
Long-term debt, net 807 (11)
Common and preferred dividends paid (5,936) (5,509)
Reduction in capital lease obligations (544) (541)
Sale of common stock 28 20
------- -------
Net cash used for financing activities (5,643) (14,791)
------- -------
Net Increase (Decrease) in Cash and Cash Equivalents 18,551 9,226
Cash and Cash Equivalents at Beginning of Period 35,461 10,051
------- -------
Cash and Cash Equivalents at End of Period $54,012 $19,277
======= =======
Supplemental Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) $ 6,946 $ 4,953
Income taxes (net of refunds) $11,379 $ 8,213
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2000
Note 1 - Accounting Policies
The Company's significant accounting policies are described in Note
1 of Notes to Consolidated Financial Statements included in its 1999
Annual Report on Form 10-K filed with the Securities and Exchange
Commission. For interim reporting purposes, the Company follows these
same basic accounting policies, but considers each interim period as an
integral part of an annual period.
The financial information included herein is unaudited; however,
such information reflects all adjustments (consisting of normal
recurring accruals) which are, in the opinion of management, necessary
for a fair statement of results for the interim periods.
Note 2 - Environmental
The Company is engaged in various operations and activities which
subject it to inspection and supervision by both federal and state
regulatory authorities including the United States Environmental
Protection Agency ("EPA"). It is Company policy to comply with all
environmental laws. The Company has implemented various procedures and
internal controls to assess and assure compliance. If non-compliance is
discovered, corrective action is taken. Based on these efforts and the
oversight of those regulatory agencies having jurisdiction, the Company
believes it is in compliance, in all material respects, with all
pertinent environmental laws and regulations.
Company operations occasionally result in unavoidable, inadvertent
releases of regulated substances or materials, for example the rupture
of a pole mounted transformer, or a broken hydraulic line. Whenever the
Company learns of such a release, the Company responds in a timely
fashion and in a manner that complies with all federal and state
requirements. Except as discussed in the following paragraphs, the
Company is not aware of any instances where it has caused, permitted or
suffered a release or spill on or about its properties or otherwise
which is likely to result in any material environmental liabilities to
the Company.
The Company is an amalgamation of more than 100 predecessor
companies. Those companies engaged in various operations and activities
prior to being merged into the Company. At least two of these companies
were involved in the production of gas from coal to sell and distribute
to retail customers at three different locations. These activities were
discontinued by the Company in the late 1940's or early 1950's. The
coal gas manufacturers, other predecessor companies, and the Company
itself may have engaged in waste disposal activities which, while legal
and consistent with commercially accepted practices at the time, may not
meet modern standards and thus represent potential liability.
The Company continues to investigate, evaluate, monitor and, where
appropriate, remediate contaminated sites related to these past
activities. The Company's policy is to accrue a liability for those
sites where costs for remediation, monitoring and other future
activities are probable and can be reasonably estimated. As part of
that process, the Company also researches the possibility of insurance
coverage that could defray any such remediation expenses.
Cleveland Avenue Property The Company's Cleveland Avenue property,
located in the City of Rutland, Vermont, was a site where one of its
predecessors operated a coal-gasification facility and later the Company
sited various operations functions. Due to the presence of coal tar
deposits and Polychlorinated Biphenyl ("PCB") contamination and
uncertainties as to potential off-site migration of those contaminants,
the Company conducted studies in the late 1980's and early 1990's to
determine the magnitude and extent of the contamination. After
completing its preliminary investigation, the Company engaged a
consultant to assist in evaluating clean-up methodologies and provide
cost estimates. Those studies indicated the cost to remediate the site
would be approximately $5.0 million. This was charged to expense in the
fourth quarter of 1992. Site investigation has continued over the last
several years and the Company continues to work with the State of
Vermont in a joint effort to develop a mutually acceptable solution.
Brattleboro Manufactured Gas Facility From the early to late 1940's,
the Company owned and operated a manufactured gas facility in
Brattleboro, Vermont ("VT"). The Company received a letter from the
State of New Hampshire ("NH")asking the Company to conduct a scoping
study in and around the site of the former facility. The Company
commissioned an environmental site assessment in late 1999. In April
2000, the Company presented the assessment findings to the states of NH
and VT and the town of Brattleboro. The State of VT concluded that
additional site monitoring is necessary. The State of NH has yet to
comment on the assessment findings. At this time the Company has not
finalized an estimate of its potential liability at this site.
Dover, New Hampshire Manufactured Gas Facility The Company was recently
contacted by Public Service Company of New Hampshire ("PSNH") with
respect to this site. PSNH alleges the Company is partially liable for
remediation of this site. PSNH's allegation is premised on the fact
that prior to PSNH's purchase of the facility, it was operated by Twin
State Gas and Electric ("Twin State"). Twin State merged with the
Company on the same day the facility was sold to PSNH. The Company is
researching the underlying transactions in an effort to determine the
nature and extent of any liability it may have. The State of NH
subsequently notified the Company that they received notice from PSNH
that the Company is liable for the site. Accordingly, the Company
responded to the State of NH and agreed to participate in future
discussions about the site but did not acknowledge liability pending the
completion of research related to the transaction. At this time, the
Company has not finalized an estimate of its potential liability at this
site.
The Company is not subject to any pending or threatened litigation
with respect to any other sites that have the potential for causing the
Company to incur material remediation expenses, nor has the EPA or other
federal or state agency sought contribution from the Company for the
study or remediation of any such sites.
As of June 30, 2000, a reserve of $9.6 million has been established
representing management's best estimate of the costs to remediate the
sites.
Note 3 - Retail Rates
The Company recognizes that adequate and timely rate relief is
necessary if it is to maintain its financial strength, particularly
since Vermont regulatory rules do not allow for changes in purchased
power and fuel costs to be automatically passed on to consumers through
rate adjustment clauses. The Company intends to continue its practice
of periodically reviewing costs and requesting rate increases when
warranted.
Vermont Retail Rate Proceedings: The Company filed for a 6.6%, or
$15.4 million per annum, general rate increase on September 22, 1997 to
become effective June 6, 1998 to offset increasing costs of providing
service. Approximately $14.3 million or 92.9% of the rate increase
request was to recover scheduled contractual increases in the cost of
power the Company purchases from Hydro-Quebec.
In response to the Company's September 1997 rate increase filing,
the Vermont Public Service Board ("PSB") decided to appoint an
independent investigator to examine the Company's decision to buy power
from Hydro-Quebec. The Company made a filing with the PSB stating that
the PSB as well as other parties should be barred from reviewing past
decisions because the PSB already examined the Company's decision to buy
power from Hydro-Quebec in a 1994 rate case in which the Company was
penalized for "improvident power supply management". During February
1998, the Vermont Department of Public Service ("DPS") filed testimony
in opposition to the Company's retail rate increase request. The DPS
recommended that the PSB instead reduce the Company's then current
retail rates by 2.5% or $5.7 million. The Company sought, and the PSB
granted, permission to stay this rate case and to file an interlocutory
appeal of the PSB's denial of the Company's motion to preclude a
re-examination of the Company's Hydro-Quebec contract in 1991. The
Company has argued its position before the Vermont Supreme Court
("VSC"). The VSC has not yet rendered a decision and it is uncertain at
this time when a decision is forthcoming.
The Company filed, on June 12, 1998 with the PSB, for a 10.7%
retail rate increase that supplanted the September 22, 1997 rate
increase request of 6.6%, to be effective March 1, 1999. On October 27,
1998, the Company reached an agreement with the DPS regarding the June
1998 retail rate increase request providing for a temporary rate
increase in the Company's Vermont retail rates of 4.7% or $10.9 million
on an annualized basis beginning with service rendered on or after
January 1, 1999. The agreement was approved by the PSB on December 11,
1998.
The 4.7% rate increase is subject to retroactive or prospective
adjustment upon future resolution of issues arising under the
Hydro-Quebec and Vermont Joint Owners ("VJO") Power Contract presently
before the VSC. The agreement temporarily disallows approximately $7.4
million (based on 1999 power costs)for the Company's purchased power
costs under the VJO Power Contract pending resolution of the issues
before the VSC. As a result of the 4.7% rate increase agreement, during
the fourth quarters of 1998 and 1999, the Company recorded
pre-tax losses of $7.4 million, and $2.9 million, respectively, for
disallowed purchased power costs, representing the Company's estimated
under recovery of power costs, prior to further resolution, under the
VJO Power Contract for 1999 and the first quarter of 2000, respectively.
In the first six months of 2000, an additional $5.7 million pre-tax loss
was recorded for the estimated under recovery of Hydro-Quebec power
costs for the second and third quarter of 2000. If in the future, the
Company is unable to increase rates to recover the temporary disallowed
purchased power costs prior to further resolution under the VJO power
contract or otherwise mitigate these costs, the Company would be
required to record losses for any estimated future under recovery.
These temporary disallowances were calculated using comparable
methodology to that used by the PSB in the Green Mountain Power ("GMP")
rate case on February 28, 1998. In that case, the PSB found GMP's
decision to commit to the VJO Power Contract in 1991 "imprudent" and
that power purchased under it was not "used and useful." As a result,
the PSB concluded that a portion of GMP's current costs should not be
imposed on GMP's customers and were disallowed. GMP is appealing that
rate order to the VSC. Should the Company receive a similar order from
the PSB, the Company would experience a material adverse effect on its
results of operations and financial condition.
If the Company receives an unfavorable ruling from the VSC and the
PSB subsequently issues a final rate order adopting the disallowance
methodology used to determine the temporary Hydro-Quebec disallowance
described above for the duration of the VJO Power Contract, the Company
would not be able to recover approximately $198.2 million of power costs
over the life of the contract, including $11.5 million in 2000, $11.6
million in 2001, $11.8 million in 2002, $11.9 in million 2003 and $12.1
million in 2004. In such an event, the Company would be required to take
an immediate charge to earnings of approximately $198.2 million
(pre-tax). Such an outcome could jeopardize the Company's ability to
continue as a going concern. However, at this time, the Company does
not believe that such a loss is probable.
On April 13, 2000, the Company and the DPS filed a stipulated
agreement with the PSB to end winter-summer rate differentials for the
Company's Vermont customers. On June 8, 2000, the PSB approved the
Company's request to end the winter-summer rate differential and,
therefore the Company will now have flat rates throughout a given year.
Winter rates will be reduced by 14.9%, while summer rates will increase
10.5%. The rate design change will be revenue neutral over a 12-month
period. The additional 2000 revenues, resulting from implementing this
change in mid-year, will be applied to reduce or eliminate certain
regulatory deferrals.
New Hampshire Retail Rate/Federal Court Proceedings: Connecticut
Valley's, retail rate tariffs, approved by the NHPUC, contain a Fuel
Adjustment Clause ("FAC") and a Purchased Power Cost Adjustment
("PPCA"). Under these clauses, Connecticut Valley recovers its
estimated annual costs for purchased energy and capacity which are
reconciled when actual data is available.
On February 28, 1997 the NHPUC published its detailed Final Plan to
restructure the electric utility industry in New Hampshire. Also on
February 28, 1997, the NHPUC, in a supplemental order specific to
Connecticut Valley, found that Connecticut Valley was imprudent for not
terminating the FERC-authorized power contract between Connecticut
Valley and the Company. The NHPUC required Connecticut Valley to give
notice to cancel its contract with the Company and denied stranded cost
recovery related to this power contract. Connecticut Valley filed for
rehearing of the February 28, 1997 NHPUC Order.
On April 7, 1997, the NHPUC issued an Order addressing certain
threshold procedural matters raised in motions for rehearing and/or
clarification filed by various parties, including Connecticut Valley,
relative to the Final Plan and interim stranded cost orders. The April
7, 1997 Order stayed those aspects of the Final Plan that were the
subject of rehearing or clarification requests and also stayed the
interim stranded cost orders for the various parties, including
Connecticut Valley. As such, those matters pertaining to the power
contract between Connecticut Valley and the Company were stayed. The
suspension of these orders was to remain in effect until two weeks
following the issuance of any order concerning outstanding requests for
rehearing and clarification.
On November 26, 1997, Connecticut Valley filed a request with the
NHPUC to increase FAC, PPCA and short-term energy purchase rates
effective on or after January 1, 1998. The requested increase in rates
resulted from higher forecast energy and capacity charges on power
Connecticut Valley purchases from the Company plus removal of a credit
effective during 1997 to refund over collections from 1996.
In an Order dated December 31, 1997 in Connecticut Valley's FAC and
PPCA docket, the NHPUC found Connecticut Valley acted imprudently by not
terminating the wholesale contract between Connecticut Valley and the
Company, notwithstanding the stays of its February 28, 1997 Orders. The
NHPUC Order further directed Connecticut Valley to freeze its current
FAC and PPCA rates (other than short term rates to be paid to certain
Qualifying Facilities) effective January 1, 1998, on a temporary basis,
pending a hearing to determine: 1) the appropriate proxy for a market
price that Connecticut Valley could have obtained if it had terminated
its wholesale contract with the Company; 2) the implications of allowing
Connecticut Valley to pass on to its customers only that market price;
and 3) whether the NHPUC's final determination on the FAC and PPCA rates
should be reconciled back to January 1, 1998 or some other date.
On January 19, 1998, Connecticut Valley and the Company filed with
the Federal District Court ("Court") for a Temporary Restraining Order
("TRO") to maintain the status quo ante by staying the NHPUC Order of
December 31, 1997 and preventing the NHPUC from taking any action that
(i) compromises cost-based rate making for Connecticut Valley; (ii)
interferes with FERC's exclusive jurisdiction over the Company's pending
application to recover wholesale stranded costs upon termination of its
wholesale power contract with Connecticut Valley; or (iii) prevents
Connecticut Valley from recovering through retail rates the stranded
costs and purchased power costs that it incurs pursuant to its
FERC-authorized wholesale rate schedule with the Company.
On February 23, 1998, the NHPUC announced in a public meeting that
it reaffirmed its finding of imprudence and designated a proxy market
price for power at 4 cents per kWh in lieu of the actual costs incurred
pursuant to the wholesale power contract with the Company. In addition,
the NHPUC indicated, subject to certain conditions which were
unacceptable to the companies, that it would permit Connecticut Valley
to maintain its current rates pending a decision in Connecticut Valley's
appeal of the NHPUC Order to the New Hampshire Supreme Court.
Based on the December 31, 1997 NHPUC Order as well as the NHPUC's
February 23, 1998 announcement, which resulted in the establishment of
Connecticut Valley's rates on a non cost-of-service basis, Connecticut
Valley no longer qualified, as of December 31, 1997, for the application
of Statement of Financial Accounting Standards No. 71 ("SFAS No. 71").
As a result, Connecticut Valley wrote-off all of its regulatory assets
associated with its New Hampshire retail business as of December 31,
1997. This write-off amounted to approximately $1.2 million on a
pre-tax basis. In addition, Connecticut Valley recorded a $5.5 million
pre-tax loss in 1997 for disallowed power costs.
On March 20, 1998, the NHPUC issued an order which affirmed,
clarified and modified various generic policy statements including the
reaffirmation to establish rates on the basis of a regional average
announced previously in its February 28, 1997 Order. The March 20, 1998
Order also addressed all outstanding motions for rehearings or
clarification relative to the policies or legal positions articulated in
the Final Plan and removed the stay covering the Company's interim
stranded cost order of April 7, 1997. In addition, the March 20, 1998
Order imposed various compliance filing requirements.
On April 3, 1998, Court held a hearing on the Companies' motion for
a TRO and Preliminary Injunction against the NHPUC at which time both
the companies and the NHPUC presented arguments. In an oral ruling from
the bench, and in a written order issued on April 9, 1998, the Court
concluded that the companies had established each of the prerequisites
for preliminary injunctive relief and directed and required the NHPUC to
allow Connecticut Valley to recover through retail rates all costs for
wholesale power that Connecticut Valley purchases from the Company
pursuant to its FERC-authorized wholesale rate schedule effective
January 1, 1998 until further court order. Connecticut Valley received
an order from the NHPUC authorizing retail rates to recover such costs
beginning in May 1998. On April 14, 1998, the NHPUC filed a notice of
appeal and a motion for a stay of the Court's preliminary injunction.
The NHPUC's request for a stay was denied. At the same time, the NHPUC
permitted Connecticut Valley to recover in rates the full cost of its
wholesale power purchases from the Company.
Also, on April 3, 1998, the Court indicated its earlier TRO
enjoining the NHPUC's restructuring orders applied to Connecticut Valley
which prohibits the enforcement of the restructuring orders until the
Court conducts a consolidated hearing and rules on the requests for
permanent injunctive relief by plaintiff PSNH and the other utilities
that had been allowed to intervene in these proceedings, including the
Company and Connecticut Valley. The plaintiffs-interveners thereafter
filed a motion asking the Court to extend its stay of action by the
NHPUC to implement restructuring and to make clear that the stay
encompasses the NHPUC's order of March 20, 1998.
As a result of these Court orders, Connecticut Valley's 1997
charges, described above, were reversed in the first quarter of 1998.
Combined, the reversal of these charges increased 1998 net income and
earnings per share of common stock by approximately $4.5 million and
$.39, respectively.
On April 1, 1998, Citizens Bank of New Hampshire ("Bank") notified
Connecticut Valley that it was in default of the Loan Agreement between
the Bank and Connecticut Valley dated December 27, 1994 and that the
Bank would exercise all of its remedies from and after May 5, 1998 in
the event that the violations were not cured. After reversing the 1997
write-offs described above, Connecticut Valley was in compliance with
the financial covenants associated with its $3.75 million loan with the
Bank. As a result, Connecticut Valley satisfied the Bank's requirements
for curing the violation.
On May 11, 1998, the NHPUC issued an order requiring Connecticut
Valley to show cause why it should not be held in contempt for its
failure to meet the compliance filing requirements of its March 20, 1998
Order. A hearing on this matter was scheduled for June 11, 1998, which
was subsequently canceled because of the Court's June 5, 1998 Order,
discussed below.
On June 5, 1998, the Court issued an Order which denied the NHPUC's
motion for a stay of the Court's preliminary injunction. The Order
clearly stated that no restructuring effort in New Hampshire can move
forward without the Court's approval unless all New Hampshire utilities
agree to the plan. The Order suspended all involuntary restructuring
efforts for all New Hampshire utilities until a hearing on the merits
was conducted. The NHPUC appealed this Order to the Court of Appeals.
On July 23, 1998, the NHPUC issued an order vacating that portion
of its February 27, 1997 restructuring order that had directed
Connecticut Valley to terminate its RS-2 wholesale power purchases from
the Company. The NHPUC has expressly stated in federal court filings
that its July 23, 1998 order "clarified that Connecticut Valley should
not terminate the RS-2 Rate Schedule if such termination would trigger
the exit fee" for which the Company has sought authorization from FERC.
On November 24, 1998, Connecticut Valley filed with the NHPUC its
annual FAC/PPCA rates to be effective January 1, 1999. On January 4,
1999, the NHPUC issued an Order allowing Connecticut Valley to implement
the proposed FAC and PPCA rates, on a temporary basis, effective on all
bills rendered on or after January 1, 1999. In addition, the NHPUC also
ordered Connecticut Valley to pay refunds plus interest to its retail
customers for any overcharges collected as a result of the April 9, 1998
Federal District Court Order, should it be overturned or modified, which
are included in the estimated total losses of $4.3 million discussed
below.
On December 3, 1998, the Court of Appeals announced its decisions
on the appeals taken by the NHPUC from the preliminary injunctions
issued by the Court. Those preliminary injunctions had stayed
implementation of the NHPUC's plan to restructure the New Hampshire
electric industry and required the NHPUC to allow Connecticut Valley to
recover through its retail rates the full cost of wholesale power
obtained from the Company.
The Court of Appeals affirmed the preliminary injunction, issued by
the Court, staying restructuring until the plaintiff utilities' claims
(including those of the Company and Connecticut Valley) are fully tried.
The Court of Appeals found that PSNH had sufficiently established that,
without the preliminary injunction against restructuring, it would
suffer substantial irreparable injury and that it had sufficient claims
against restructuring to warrant a full trial. The Court of Appeals
also affirmed the extension of the preliminary injunction to protect the
other plaintiff utilities, including Connecticut Valley and the Company,
although it questioned whether the other utilities had arguments as
strong against restructuring as PSNH because they did not have formal
agreements with the State similar to PSNH's Rate Agreement. The Court
of Appeals stated that if the Court awards the utilities permanent
injunctive relief against restructuring after the case is tried, then it
must explain why the other utilities are also entitled to such relief.
The NHPUC filed a petition for rehearing on December 17, 1998. The
Court of Appeals denied the petition on January 13, 1999.
The Court of Appeals also reversed the Court's preliminary
injunction requiring the NHPUC to allow Connecticut Valley to recover in
retail rates the full cost of the power it buys from the Company.
Although the Court of Appeals found that Connecticut Valley and the
Company had made a strong showing of irreparable injury to justify the
preliminary injunction, it concluded that Connecticut Valley's and the
Company's claims did not have a sufficient probability of success to
warrant such preliminary relief. The Court of Appeals explained that
the filed-rate doctrine preserving the exclusive jurisdiction of the
FERC over wholesale power rates did not prevent the NHPUC from deciding
whether Connecticut Valley's power purchases from the Company were
prudent given alternative available sources of wholesale power. The
Court of Appeals then stated that Connecticut Valley's rates could be
reduced to the level prevailing on December 31, 1997. However, the
Court of Appeals also stated that if the NHPUC ordered Connecticut
Valley's rates to be reduced below the level existing as of December 31,
1997, "it will be time enough to consider whether they are precluded
from the Court's injunction against the Final Plan or on other grounds."
On December 17, 1998, Connecticut Valley and the Company filed a
petition for rehearing on the grounds that the Court of Appeals had not
given sufficient weight to the Court's factual findings and that the
Court of Appeals had misapprehended both factual and legal issues.
Connecticut Valley and the Company also asked that the entire Court of
Appeals, rather than only the three-judge appellate panel that had
issued the December 3 decision, consider their petition for rehearing.
On January 13, 1999, the Court of Appeals denied the petition for
rehearing.
Connecticut Valley and the Company then requested the Court of
Appeals to stay the issuance of its mandate until the companies could
file a petition of certiorari to the United States Supreme Court and the
Supreme Court acted on the petition.
On January 22, 1999, the Court of Appeals denied the request.
However, the Court of Appeals granted a 21-day stay to enable the
Company to seek a stay pending certiorari from the Circuit Justice of
the Supreme Court. On February 11, 1999, the Company and Connecticut
Valley filed a petition for a writ of certiorari with the United States
Supreme Court and a motion to stay the effect of the Court of Appeals'
decision while the case was pending in the Supreme Court. The motion
for a stay was addressed to Justice Souter who is responsible for such
motions pertaining to the Court of Appeals for the First Circuit. On
February 18, 1999, Justice Souter denied the stay pending the petition
for certiorari. On April 19, 1999, the Supreme Court denied the
petition for certiorari.
As a result of the December 3, 1998 Court of Appeals' decision
discussed above, on March 22, 1999, the NHPUC issued an Order which
directed Connecticut Valley to file within five business days its
calculation of the difference between the total FAC and PPCA revenues
that it would have collected had the 1997 FAC and PPCA rate levels been
in effect the entire year. In its Order, the NHPUC also directed
Connecticut Valley to calculate a rate reduction to be applied to all
billings for the period April 1, 1999 through December 31, 1999, to
refund the 1998 over collection relative to the 1997 rate level. The
Company estimated this amount to be approximately $2.7 million on a
pre-tax basis. Connecticut Valley filed the required tariff page with
the NHPUC, under protest and with reservation of all rights, on March
26, 1999, and implemented the refund effective April 1, 1999.
As a result of legal and regulatory actions discussed above,
Connecticut Valley no longer qualified as of December 31, 1998 for the
application of SFAS No. 71, and wrote-off in the fourth quarter of 1998
all of its regulatory assets associated with its New Hampshire retail
business estimated at approximately $1.3 million on a pre-tax basis at
December 31, 1998. In addition, Connecticut Valley recorded estimated
total losses of $4.3 million pre-tax during the fourth quarter of 1998
for disallowed power costs of $1.6 million and its refund obligations of
$2.7 million.
The pre-tax losses described above resulted in Connecticut Valley
violating applicable covenants, which if not waived or renegotiated,
would have allowed Connecticut Valley's lender the right to accelerate
the repayment of a $3.75 million loan with Connecticut Valley. On March
12, 1999, Connecticut Valley was notified by the Bank that it would
exercise appropriate remedies in connection with the violation of
financial covenants associated with the $3.75 million loan agreement
unless the violation was cured by April 11, 1999. To avoid default of
this loan agreement, on April 6, 1999, pursuant to an agreement reached
on March 26, 1999, the Company purchased from the Bank the $3.75 million
note.
On April 7, 1999, the Court ruled from the bench that the March 22,
1999 NHPUC Order requiring Connecticut Valley to provide a refund to its
retail customers was illegal and beyond the NHPUC's authority. The
Court also ruled that the NHPUC cannot reduce Connecticut Valley's rates
below rates in effect at December 31, 1997. Accordingly, Connecticut
Valley removed the rate refund from retail rates effective April 16,
1999. Lastly, the Court denied the NHPUC's motion to dissolve the
injunction staying the implementation of its restructuring plan and
stated its desire to rule on the pending motion for summary judgement
and to conduct a hearing on the Company's request for a permanent
injunction, after the NHPUC completes hearings on PSNH's stranded costs.
The District Court's decision was issued as a written order on May 11,
1999.
The NHPUC held a hearing on April 22, 1999 to determine whether to
modify Connecticut Valley's 1999 power rates by returning the rates to
the levels that were in effect on December 31, 1997. On May 17, 1999,
the NHPUC issued an order requiring Connecticut Valley to set temporary
rates at the level in effect as of December 31, 1997, subject to future
reconciliation, effective with bills issued on and after June 1, 1999.
On May 24, 1999, the NHPUC filed a petition for mandamus in the
Court of Appeals challenging the Court's May 11, 1999 ruling and seeking
a decision allowing the refunds as required by the NHPUC's March 22,
1999 order. The Court of Appeals denied that petition on June 2, 1999.
The NHPUC immediately filed a Notice of Appeal in the Court of Appeals
again challenging the Court's May 11, 1999 ruling. In that appeal, the
Company and Connecticut Valley contend, among other things, that it is
unfair for the NHPUC to direct Connecticut Valley to continue to
purchase wholesale power under RS-2 in order to avoid the triggering of
a FERC exit fee, but at the same time to freeze Connecticut Valley's
rates at their December 31, 1997 level which does not enable Connecticut
Valley to recover all of its RS-2 costs.
On June 14, 1999, PSNH and various parties in New Hampshire
announced that a "Memorandum of Understanding" had been reached that is
intended to result in a detailed settlement proposal to the NHPUC that
would resolve PSNH's claims against the NHPUC's restructuring plan. On
July 6, 1999, PSNH petitioned the Court to stay its proceedings
indefinitely while the proposed settlement is reviewed and approved by
the NHPUC and the New Hampshire Legislature. On July 12, 1999, the
Company and Connecticut Valley objected to any stay that would allow the
NHPUC's rate freeze order to remain in effect for an extended period and
asked the Court to proceed with prompt hearings on its summary judgement
motion and trial on the merits. On October 20, 1999, the Court heard
oral arguments pertaining to the pretrial motions of the Company and the
NHPUC for summary judgement and dismissal, respectively.
On December 1, 1999, Connecticut Valley filed with the NHPUC a
petition for a change in its FAC and PPCA rates effective on bills
rendered on and after January 1, 2000. On December 30, 1999, the NHPUC
denied Connecticut Valley's request to increase its FAC and PPCA rates
above those in effect at December 31, 1997, subject to further
investigation and reconciliation until otherwise ordered by the NHPUC.
Accordingly, during the fourth quarter of 1999 Connecticut Valley
recorded a pre-tax loss of $1.2 million for under collection of year
2000 power costs.
The Court of Appeals issued a decision on January 24, 2000, which
upheld the Court's preliminary injunction enjoining the Commission's
restructuring plan. The decision also remanded the refund issue to the
Court stating:
"the district court may defer vacation of this injunction against
the refund order for up to 90 days. If within that period it has
decided the merits of the request for a permanent injunction in a
way inconsistent with refunds, or has taken any other action that
provides a showing that the Company is likely to prevail on the
merits in federal court in barring the refunds, it may enter a
superseding injunction against the refund order, which the
Commission may then appeal to us. Otherwise, no later than the end
of the 90-day period, the district court must vacate its present
injunction insofar as it enjoins the Commission's refund order."
On March 6, 2000, the Court granted summary judgment to Connecticut
Valley and the Company on their claim under the filed-rate doctrine and
issued a permanent injunction mandating that the NHPUC allow Connecticut
Valley to pass through to its retail customers its wholesale costs
incurred under the RS-2 rate schedule with the Company. The Court also
ruled that Connecticut Valley is entitled to recover those wholesale
costs that the NHPUC has disallowed in retail rates since January 1,
1997. This decision is subject to implementation by the NHPUC and has
been appealed by the NHPUC to the Court of Appeals. The NHPUC also
requested the Court of Appeals to stay the Court's order pending the
Court's review on appeal. In response, Connecticut Valley offered to
place the additional revenues in escrow pending the outcome of appeal.
The Court of Appeals denied the NHPUC's request for a stay so long as
the incremental revenues were placed in escrow.
Pursuant to the March 6, 2000 Court's Order, on March 17, 2000
Connecticut Valley filed a rate request with the NHPUC for an Interim
FAC/PPCA to recover the balance of wholesale costs not recovered since
January 1997. To mitigate the rate increase percentage, the Interim
FAC/PPCA were designed to recover current power costs and a substantial
portion of past under collections by the end of 2000; the remainder of
the past under collections will be collected during 2001 along with 2001
power costs. The NHPUC held a hearing on April 7, 2000 to review the
12.3% increase that would raise $1.6 million of revenues in 2000. The
NHPUC issued an order approving the rates as temporary effective May 1,
2000.
On July 25, 2000, the Court of Appeals affirmed the Court's March
6, 2000 Order granting summary judgement to Connecticut Valley and the
Company. The Court of Appeals decision is subject to a reconsideration
and an appeal process. None the less, those amounts held in escrow have
been released to the Company as a result of the March 6, 2000 order.
Federal Energy Regulatory Commission ("FERC") Proceedings: The Company
filed an application with the FERC in June 1997, to recover stranded
costs in connection with its wholesale rate schedule with Connecticut
Valley and a notice of cancellation of the Connecticut Valley rate
schedule (contingent upon the recovery of the stranded costs that would
result from the cancellation of this rate schedule). In December 1997,
the FERC rejected the Company's proposal to recover stranded costs
through the imposition of a surcharge on our transmission tariff, but
indicated that it would consider an exit fee mechanism for collecting
stranded costs. The FERC denied the Company's motion for a rehearing
regarding the surcharge proposal, so the Company filed a request with
the FERC for an exit fee mechanism to collect the stranded costs
resulting from the cancellation of the contract with Connecticut Valley.
The stranded cost obligation sought to be recovered through an exit fee,
expressed on a net present value basis as of January 1, 2000, is
approximately $44.9 million. On September 14 and 15, 1998 the Company
participated in a settlement conference with an Administrative Law Judge
assigned for the settlement process at the FERC and the parties to the
Company's exit fee filing. During April and May 1999, nine days of
hearings were held at the FERC before an Administrative Law Judge, who
will determine, among other things, whether Connecticut Valley qualifies
for an exit fee, and if so, the amount of Connecticut Valley's stranded
cost obligation to be paid to the Company as an exit fee. The ruling of
the Administrative Law Judge could be issued at any time. Thereafter
the FERC will act on the judge's recommendations.
If the Company is unable to obtain an order authorizing the
recovery of costs in connection with the June 1997 FERC filing or in the
Federal Court, it is possible that the Company would be required to
recognize a pre-tax loss under this contract totaling approximately
$56.3 million as of December 31, 1999. The Company would also be
required to write-off approximately $3.0 million (pre-tax) in regulatory
assets associated with its wholesale business as of December 31, 1999.
However, even if the Company obtains a FERC order authorizing the
updated requested exit fee, if Connecticut Valley is unable to recover
its costs by increasing its rates, Connecticut Valley would be required
to recognize a loss under this contract of approximately $44.9 million
(pre-tax) representing future under recovery of power costs as of
December 31, 1999.
In addition to its efforts before the Court and FERC, Connecticut
Valley has initiated efforts and will continue to work for a negotiated
settlement with parties to the New Hampshire restructuring proceeding
and the NHPUC.
An adverse resolution of these proceedings would have a material
adverse effect on the Company's results of operations and cash flows.
However, the Company cannot predict the ultimate outcome of this matter.
Claremont Municipalization
In the summer of 1997, the City of Claremont ("Claremont"), New
Hampshire engaged a consulting firm to conduct a study to determine
Claremont's options under New Hampshire law including the possible
municipalization of Connecticut Valley's service area located within its
jurisdiction. The City Council ("Council") appropriated approximately
$75,000 for purposes of the study which has been completed. In May
1999, the City Council of Claremont considered whether to publicly warn
a vote to acquire the Company's facilities located in Claremont and to
establish a municipal electric utility pursuant to N.H.R.S.A. Chapter 38
et. sec. By vote of six to three, the Council voted to proceed towards
the establishment of a municipal electric utility and acquisition of
Company facilities. This action required that Claremont hold an
election within one year of the Council's action to determine if a
majority of the qualified voters will confirm the Council's decision.
Should the Council's decision be confirmed by Claremont voters, the
Council will have thirty days from the date of the confirming vote to
notify the Company of its intention to purchase all or such portion of
the Company's plant and property located within Claremont and such
portion of the plant lying within the municipality as the public
interest may require. The Company would thereafter have sixty days to
reply to the Claremont's inquiry. If there is no agreement between the
Company and Claremont, Claremont may proceed to condemn the Company's
facilities with proceedings before the NHPUC as provided for in Chapter
38 and the FERC as provided for in its Rule 35.26 (18CFR Chapter 1). On
September 8, 1999, the City Council voted to postpone indefinitely the
citizens' vote on municipalization which had been set for November 2,
1999. A group of Claremont citizens opposed to a government electric
takeover actively participated in the November 2, 1999 municipal
election, resulting in the election of three challengers opposed to the
idea, and the creation of a majority on the city council against the
municipalization of Connecticut Valley's system. The Company cannot
predict at this time when or if a citizens' vote on municipalization
will be held in connection with this initiative.
Note 4 - Segment Reporting
Operating segments are defined as components of an enterprise about
which separate financial information is available that is evaluated
regularly by the chief operating decision maker, or decision making
group, in deciding how to allocate resources and in assessing
performance. The Company's chief operating decision making group is the
Board of Directors, which is comprised of nine Directors including the
Chairman of the Board and the Company's President and Chief Executive
Officer. The operating segments are managed separately because each
operating segment represents a different retail rate jurisdiction or
offers different products or services.
The Company's reportable operating segments include Central Vermont
Public Service Corporation ("CV") which engages in the purchase,
production, transmission, distribution and sale of electricity in
Vermont; Connecticut Valley Electric Company Inc. ("CVEC") which
distributes and sells electricity in parts of New Hampshire; Catamount
which invests in non-regulated, energy-supply projects and SmartEnergy
which pursues retail alliances to market energy and related products and
services, engages in the sale of or rental of electric water heaters and
has a 37.5% ownership interest in The Home Service Store, Inc. ("HSS").
CVEC, while managed on an integrated basis with CV, is presented
separately because of its separate and distinct regulatory jurisdiction.
Other operating segments include a segment below the quantitative
threshold for separate disclosure. This operating segment is C. V.
Realty, Inc., a real estate company whose purpose is to own, acquire,
buy, sell and lease certain real and personal property and interests
therein related to the utility business. Segment information for the
second quarter of 1999 has been restated to separately present
SmartEnergy which became a reportable segment during the fourth quarter
of 1999.
The accounting policies of the operating segments are the same as
those described in Note 1 to Consolidated Financial Statements included
in its 1999 Annual Report on Form 10-K filed with the Securities and
Exchange Commission. Intersegment revenues include sales of purchased
power to Connecticut Valley and revenues for support services to
Connecticut Valley, Catamount and SmartEnergy.
These intersegment sales and services for each jurisdiction are
based on actual rates or current costs. The Company evaluates
performance based on stand alone operating segment net income.
Financial information by industry segment for the three and six
months ended June 30, 2000 and 1999, is as follows (dollars in
thousands):
<TABLE>
<CAPTION>
Reclassifications
Three Months Ended June 30 CV CVEC & Consolidating
2000 Vermont New Hampshire Catamount SmartEnergy Other<F1> Entries Consolidated
---- ------- ------------- --------- ----------- ------- ----------------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues from external
customers $ 69,932 $ 4,637 $ 125 $ 768 $ 895 $ 73,867
Intersegment revenues 3,322 3,322 -
Net income (loss) 44 (263) 40 450 $ 3 - 274
Total assets $489,936 $12,245 $46,039 $ 5,544 $ 307 $ 6,252 $547,819
1999
----
Revenues from external
customers $ 88,221 $ 4,918 $ 166 $ 1,964 $ 2 $ 2,132 $ 93,139
Intersegment revenues 3,132 3,132 -
Net income (loss) 248 271 308 (413) 2 - 416
Total assets $468,220 $12,639 $43,954 $ 4,725 $ 358 $ 5,795 $524,101
(1) Includes segments below the quantitative threshold for separate disclosure.
</TABLE>
<TABLE>
<CAPTION>
Reclassifications
Six Months Ended June 30 CV CVEC & Consolidating
2000 Vermont New Hampshire Catamount SmartEnergy Other<F1> Entries Consolidated
---- -------- ------------- --------- ----------- -------- ----------------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues from external
customers $164,170 $ 9,649 $ 224 $ 1,656 $ 1,883 $173,816
Intersegment revenues 6,457 6,457 -
Net income (loss) 10,426 (154) 297 (2,341) $ 5 - 8,233
Total assets $489,936 $12,245 $46,039 $ 5,544 $ 307 $ 6,252 $547,819
1999
----
Revenues from external
customers $180,480 $11,303 $ 295 $ 4,284 $ 4 $ 4,585 $191,781
Intersegment revenues 6,455 6,455 -
Net income (loss) 12,459 324 913 (554) 4 - 13,146
Total assets $468,220 $12,639 $43,954 $ 4,725 $ 358 $ 5,795 $524,101
(1) Includes segments below the quantitative threshold for separate disclosure.
</TABLE>
Note 5 - Investment in Vermont Yankee Nuclear Power Corporation
The Company accounts for its investment in Vermont Yankee using the
equity method. Summarized financial information for Vermont Yankee Nuclear
Power Corporation follows:
Three Months Ended Six Months Ended
June 30 June 30
2000 1999 2000 1999
---- ---- ---- ----
Operating revenues $44,702 $46,376 $85,394 $90,153
Operating income $ 4,027 $ 3,607 $ 7,910 $ 7,393
Net income $ 1,639 $ 1,638 $ 3,383 $ 3,294
Company's equity in net income $ 524 $ 523 $ 1,060 $ 1,041
Note 6 - Subsequent Events:
---------------------------
Millstone 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, both Northeast Utilities
("NU") affiliates, and lawsuits against NU and its trustees. The arbitration
and lawsuits seek to recover costs associated with replacement power,
operation and maintenance costs and other costs resulting from the shutdown of
Unit #3. The non-operating owners claim that NU and two of its wholly owned
subsidiaries failed to comply with NRC's regulations, failed to operate the
facility in accordance with good operating practice and attempted to conceal
their activities from the non-operating owners and the NRC.
On July 27, 2000, the Company executed a settlement agreement with NU,
resolving all issues asserted by the Company in the arbitration and lawsuits.
The settlement will become effective upon the approval of the Company's
withdrawal from these actions.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
June 30, 2000
Earnings Overview
The Company recorded net income and a loss per share of common stock for
the quarter ended June 30, 2000 of $.3 million and ($.01) compared to $.4
million and $.00 for the corresponding period last year.
Lower second quarter 2000 earnings compared to last year resulted
primarily from expenses booked of $1.7 million after-tax, or $.15 per share of
common stock, for expected under recovery of power costs to be incurred on the
Hydro-Quebec (HQ) power contract during the third quarter of 2000. In
addition, Catamount Energy Corporation had lower net earnings of $.3 million
after-tax, or $.03 per share of common stock. This was offset by improved net
earnings compared to last year, primarily related to SmartEnergy's partial
ownership of Home Service Store, Inc. ($.9 million after-tax, or $.08 per
share of common stock) and favorable utility revenues of $1.1 million
after-tax, or $.09 per share of common stock, primarily resulting from retail
customer mix and a 2.2% (11,749 mWh) increase in retail mWh sales.
In the first six months of 2000, the Company had net income of $8.2
million, or $.64 per share of common stock, compared to net income of $13.1
million or $1.07 per share of common stock, for the first six months of 1999.
Lower six month 2000 earnings compared to last year resulted primarily
from expenses booked of $3.4 million after-tax, or $.30 per share of common
stock for expected under recovery of power costs to be incurred on the
Hydro-Quebec (HQ) power contract during the second and third quarters of 2000
and increased net losses at Smart Energy Services, Inc. (incurred in the first
quarter of 2000) compared to last year ($1.8 million after-tax, or $.15 per
share of common stock.)
Other factors affecting results for 2000 are described in Results of
Operations below.
RESULTS OF OPERATIONS
The major elements of the Consolidated Statement of Income are discussed
below.
Operating Revenues and mWh Sales
A summary of mWh sales and operating revenues for the three and six
months ended June 30, 2000 and 1999 (and the related percentage changes from
1999) is set forth below:
<TABLE>
<CAPTION>
Three Months Ended June 30
Percentage Percentage
mWh Sales Increase Revenues (000's) Increase
2000 1999 (Decrease) 2000 1999 (Decrease)
<S> <C> <C> <C> <C> <C> <C>
Retail sales:
Residential 217,814 212,248 2.6 $26,538 $25,159 5.5
Commercial 221,891 228,114 (2.7) 24,349 23,704 2.7
Industrial 110,015 97,612 12.7 8,222 7,303 12.6
Other retail 1,574 1,571 .2 446 449 (.7)
------- --------- ------- -------
Total retail sales 551,294 539,545 2.2 $59,555 $56,615 5.2
------- --------- ------- -------
Resale sales:
Firm 439 432 1.8 $ 32 $ 37 (12.0)
Entitlement 79,388 54,155 46.6 2,798 3,031 (7.7)
Alliance 89,000 725,924 (87.7) 3,398 25,305 (86.6)
Other 205,026 274,702 (25.4) 7,107 4,303 65.2
--------- ---------- ------- -------
Total resale sales 373,853 1,055,213 (64.6) $13,335 $32,676 (59.2)
--------- --------- ------- -------
Other revenues - - - $ 977 $ 1,663 (41.2)
--------- --------- ------- -------
Total sales 925,147 1,594,758 (42.0) $73,867 $90,954 (18.8)
========= ========== ======= ========
</TABLE>
<TABLE>
<CAPTION>
Six Months Ended June 30
Percentage Percentage
mWh Sales Increase Revenues (000's) Increase
2000 1999 (Decrease) 2000 1999 (Decrease)
<S> <C> <C> <C> <C> <C> <C>
Retail sales:
Residential 495,167 486,945 1.7 $ 64,968 $ 63,852 1.8
Commercial 452,491 463,434 (2.4) 52,356 54,028 (3.1)
Industrial 235,657 212,793 10.7 19,767 18,579 6.4
Other retail 3,139 3,109 1.0 889 888 -
--------- --------- ------- -------
Total retail sales 1,186,454 1,166,281 1.7 $137,980 $137,347 .5
--------- --------- ------- -------
Resale sales:
Firm 1,102 1,346 (18.1) $ 70 $ 79 (10.5)
Entitlement 134,978 108,583 24.3 4,754 5,135 (7.4)
Alliance 450,800 949,161 (52.5) 16,510 31,714 (47.94)
Other 361,935 539,423 (32.9) 11,606 10,542 10.1
--------- --------- ------- -------
Total resale sales 948,815 1,598,513 (40.6) $ 32,940 $ 47,470 (30.6)
--------- --------- ------- -------
Other revenues - - - $ 2,896 $ 2,152 34.6
--------- --------- ------- -------
Total sales 2,135,269 2,764,794 (22.8) $173,816 $186,969 (7.0)
========= ========== ======== ========
</TABLE>
Retail mWh sales for the second quarter of 2000 increased 2.2%
compared to the second quarter of 1999 and retail revenues increased
$2.9 million, or 5.2% compared to last year. This retail revenues
variance is attributable to a $.9 million impact of higher mWh sales in
the second quarter of 2000 as compared to the second quarter of 1999 and
a $2.0 million increase in price, primarily from the commercial sector.
For the first half of 2000, retail mWh sales increased 1.7%
compared to the first half of 1999, primarily from the industrial
sector.
Effective January 1, 2000 power purchased from Hydro-Quebec is
recorded net of entitlement sales to Hydro-Quebec. The 1999 entitlement
sales included in Resale sales has been restated for comparison
purposes, along with Purchased and Produced Energy (mWh) shown in the
table below.
Alliance resale sales decreased 636,924 mWh and 498,361 mWh and
related revenues decreased $21.9 million and $15.2 million for the
second quarter and first half of 2000, respectively. This decrease
results from reduced activity by the Company through its alliance with
Virginia Power in jointly supplying wholesale power primarily in the
Northeast states. In the third quarter of 1999 the Company decided to
discontinue this alliance.
For the second quarter and first six months of 2000, other resale
sales decreased 69,676 mWh and 177,488 mWh and related revenues
increased $2.8 million and $1.1 million, respectively. These variances
reflect current market conditions in Vermont and New England. These
sales made on a short-term basis include sales to the New England Power
Pool ("NEPOOL") and other utilities in New England.
Other revenues decreased for the second quarter of 2000 primarily
due to the recording of $1.1 million associated with the 1999 and 2000
provisions for rate refund for Connecticut Valley.
Net Purchased Power and Production Fuel Costs
The net cost components of purchased power and production fuel
costs for the three and six months ended June 30, 2000 and 1999 are as
follows (dollars in thousands):
<TABLE>
<CAPTION>
Three Months Ended June 30
2000 1999
Units Amount Units Amount
<S> <C> <C> <C> <C>
Purchased and produced:
Capacity (mW) 404 $24,001 749 $22,427
Energy (mWh) 835,209 20,430 1,541,384 38,287
------- -------
Total purchased power costs $44,431 $60,714
Production fuel (mWh) 135,263 1,203 90,202 730
------- -------
Total purchased power and
production fuel costs $45,634 $61,444
Entitlement and other resale sales (mWh) 373,853 13,335 1,055,213 32,676
------- -------
Net purchased power and production
fuel costs $32,299 $28,768
======= =======
</TABLE>
<TABLE>
<CAPTION>
Six Months Ended June 30
2000 1999
Units Amount Units Amount
<S> <C> <C> <C> <C>
Purchased and produced:
Capacity (mW) 432 $ 46,847 917 $ 44,911
Energy (mWh) 1,989,504 51,161 2,671,943 63,211
------- -------
Total purchased power costs $ 98,008 $108,122
Production fuel (mWh) 251,262 2,056 205,616 1,346
------- -------
Total purchased power and
production fuel costs $100,064 $109,468
Entitlement and other resale sales (mWh) 948,815 32,940 1,598,513 47,470
------- -------
Net purchased power and production
fuel costs $ 67,124 $ 61,998
======= =======
</TABLE>
Purchased and produced capacity (mW) costs increased $1.6 million
for the second quarter of 2000 versus last year, primarily due to an
additional $2.9 million pre-tax loss for the estimated future under
recovery of Hydro-Quebec power costs for the third quarter of 2000.
Partially offsetting this increase is the positive impact of $1.0
million for Hydro-Quebec power cost reversals, representing the reversal
of a portion of disallowed Hydro-Quebec power costs accrued during the
fourth quarter of 1998, and 1999 and lower Vermont Yankee capacity costs
of $.5 million.
Purchased and produced energy (mWh) purchases decreased $17.9
million for the second quarter of 2000 primarily due to a 45.8%, or
$17.5 million decrease in the amount of mWh purchased primarily related
to reduced activity with Virginia Power.
For the first half of 2000, net purchased power and production fuel
costs increased $5.1 million or 8.3% compared to the first half of 1999
primarily due to an additional $5.7 million pre-tax loss for the
estimated future under recovery of Hydro-Quebec power costs.
NUCLEAR MATTERS
The Company maintains a 1.7303% joint-ownership interest in the
Millstone Unit #3 ("Unit #3"), an 1149 mW nuclear unit of the Millstone
Nuclear Power Station and owns a 2% equity interest in Connecticut
Yankee. These two plants are operated by NU. The Company also owns 2%,
3.5% and 31.3% equity interest in Maine Yankee, Yankee Atomic and
Vermont Yankee, respectively.
Millstone Unit #3
On September 15, 1999, NU announced that it intends to auction its
nuclear generating plants, including Unit #3. We cannot predict at this
time the effect of such an auction on the Company.
Maine Yankee
On August 6, 1997, the Maine Yankee's nuclear power plant was
prematurely retired from commercial operation. The Company relied on
Maine Yankee for less than 5% of its required system capacity. Future
payments for the closing, decommissioning and recovery of the remaining
investment in Maine Yankee are estimated to be approximately $715.0
million in 1998 dollars including a decommissioning obligation of $344.0
million.
On January 19, 1999, Maine Yankee and the active interveners filed
an Offer of Settlement with the FERC which the FERC has approved. As a
result, all issues raised in the FERC proceeding, including recovery of
anticipated future payments for closing, decommissioning and recovery of
the remaining investment in Maine Yankee are resolved. Also resolved are
the issues raised by the secondary purchasers, who purchased Maine
Yankee power through agreements with the original owners, by limiting
the amounts they will pay for decommissioning the Maine Yankee plant and
by settling other points of contention affecting individual secondary
purchasers. As a result, it is possible that the Company will not be
able to recover approximately $.5 million of these costs.
Connecticut Yankee
On December 4, 1996, the Connecticut Yankee Nuclear power plant was
prematurely retired from commercial operation. The Company relied on
Connecticut Yankee for less than 3.0% of its required system capacity.
On August 31, 1998, a FERC Administrative Law Judge recommended
that the owners of Connecticut Yankee, including the Company, may
collect from customers $350.0 million for decommissioning the
Connecticut Yankee Nuclear Power Plant rather than the $426.7 million
requested. The Administrative Law Judge ruling is subject to approval
by the FERC Commissioners. If approved, it is possible that the Company
would not be able to recover approximately $1.5 million of
decommissioning costs through the regulatory process.
Yankee Atomic
In 1992, the Yankee Atomic nuclear power plant was retired from
commercial operation. The Company relied on Yankee Atomic for less than
1.5% of its system capacity.
Vermont Yankee
During 1996, Vermont Yankee initiated a Design Basis Documentation
project expected to be complete by December 31, 2001. This project was
undertaken to incorporate all design documentation into a centralized
system. The objective is to ensure that Vermont Yankee maintains its
safety margins in connection with any plant modifications. The Design
Basis Documentation project will create a set of design basis documents
which will support more efficient systematic problem solving,
maintenance, and system overview. This effort supports the safe, cost
effective, long term operation of the Vermont Yankee Plant. Vermont
Yankee received FERC approval in 1996 to defer these unrecovered study
costs and amortize the costs through billings to Sponsors over the
remaining license life of the Plant. The Company's 35% share of the
total cost for this Project is expected to be between $5.5 million and
$6.2 million.
On October 15, 1999, the Company and the other owners of Vermont
Yankee accepted a bid for sale of the plant to AmerGen Energy Co.,
which is owned by PECO Energy Company and British Energy. On November
17, 1999, Vermont Yankee executed an Asset Purchase Agreement with
AmerGen Energy Co. The Agreement is subject to several conditions,
including approvals or specific rulings by various regulatory
authorities. As such, execution of the Agreement does not provide
assurance that the sale will occur. This agreement will also involve
the Company entering into a contract to purchase a portion of the power
produced by this plant.
Vermont Yankee estimates that the price to be paid by AmerGen for
the non-transmission assets will range from $10 million to $23.5 million
depending on when the sale occurs. Additionally, Vermont Yankee's
current owners will make a one-time payment of approximately $54.0
million to pre-pay the plant's decommissioning fund and to pay the
Texas, Maine and Vermont Low-Level Waste compact fees. Based on the
expected regulatory treatment of these costs, the Company does not
believe the sale will have a material impact on the financial condition
or operation of the Company. Proceedings before the Vermont Public
Service Board for approval of the sale have ended and the Board is
expected to issue a decision by late summer or early fall.
Maine Yankee, Connecticut Yankee and Yankee Atomic Decommissioning Costs
Presently, costs billed to the Company by Maine Yankee, Connecticut
Yankee and Yankee Atomic, including a provision for ultimate
decommissioning of the units, are being collected from the Company's
customers through existing retail and wholesale rate tariffs. The
Company's share of remaining costs with respect to Maine Yankee,
Connecticut Yankee and Yankee Atomic's decisions to discontinue
operation is estimated to be $12.2 million, $7.7 million and $.1
million, respectively, at June 30, 2000. These amounts are subject to
ongoing review and revisions and are reflected in the accompanying
balance sheet both as regulatory assets and nuclear dismantling
liabilities (current and non-current).
The decision to prematurely retire these nuclear power plants was
based on economic analyses of the costs of operating them compared to
the costs of closing them and incurring replacement power costs over the
remaining period of the plants' operating licenses. The Company
believes that based on the current regulatory process, its proportionate
share of Maine Yankee, Connecticut Yankee and Yankee Atomic
decommissioning costs will be recovered through the regulatory process
and, therefore, the ultimate resolution of the premature retirement of
the three plants has not and should not have a material adverse effect
on the Company's earnings or financial condition.
Generating Units
The Company owns and operates 20 hydroelectric generating units and
two gas turbines and one diesel peaking unit with a combined nameplate
capability of 73.7 mW.
The Company is currently in the process of relicensing or preparing
to relicense eight separate hydroelectric projects under the Federal
Power Act. These projects, some of which are grouped together under a
single license, represent approximately 29.9 mW, or about 72.4% of the
Company's total hydroelectric nameplate capacity. In the new licenses,
the FERC is expected to impose conditions designed to address the impact
of the projects on fish and other environmental concerns. The Company
is unable to predict the impact of the imposition of such conditions,
but capital expenditures and operating costs are expected to increase
and net generation from these projects will decrease in future periods.
In addition, the Company maintains joint-ownership interests in
Joseph C. McNeil, a 53 mW wood, gas and oil-fired unit and Wyman #4, a
619 mW oil-fired unit.
Transmission Matters
Vermont Electric Power Company, Inc. ("VELCO") owns and operates
most of the high voltage transmission system in Vermont. The Company
owns 56.8% of the Class B common stock of VELCO and 46.6% of the Class C
preferred stock of VELCO. Approximately 47% of VELCO's costs are borne
by the Company.
On March 22, 2000, the phase angle regulator (PAR), which controls
power flows over the transmission line between Plattsburg, New York, and
Milton, Vermont, suffered a serious failure of insulation in its
windings. Automatic equipment immediately took the line out of service.
Operations were restored within a week, but without the PAR. The PAR,
which is owned by the New York Power Authority (NYPA), will be repaired.
VELCO has requested NYPA to commence repairs, and has informed NYPA that
VELCO will bear the cost of repair, to the extent that regulatory
authorities do not allocate any of the costs to others. The final costs
to repair the PAR and CV's share of such costs is not currently known.
The unit has been shipped to the repair facility and is expected to be
returned to service by about February 2001.
To compensate for the loss of PAR control, VELCO plans to operate
the affected transmission line during high load periods by employing
inductor coils to provide impedance to restrict flows across the line.
This mode of operation will increase reactive power support requirements
in Vermont. Consequently, VELCO has installed one synchronous condenser
near the Vermont terminus of this line to provide that support. The
unit will be operable as either a generator or a synchronous condenser,
and it is continuing studies to determine the need for a second unit.
VELCO received all required regulatory approvals and permits required
for the installation.
The total cost of the facilities VELCO has installed will be
substantial (approximately $10.0 million of expenses through April
2001). Such costs will be spread among all electric customers in New
England. The total cost to be borne by VELCO will be about 5% of the
total.
VELCO is also in the process of installing a Flexible Alternating
Current Transmission System ("FACTS") device which will, by itself,
provide the reactive support required for the operation of this
Plattsburg, NY to Milton, VT line. The FACTS device is on schedule to
be in service May 1, 2001.
The start-up of the FACTS device will significantly reduce the
current need for the Joseph C. McNeil generating plant to run in support
of area reliability.
Merrimack Unit #2
Until its termination on April 30, 1998, the Company purchased
power and energy from Merrimack #2, pursuant to a contract dated July
16, 1966 entered into by and between VELCO and PSNH. Pursuant to the
contract, as amended, VELCO agreed to reimburse PSNH, in the proportion
which the VELCO quota bears to the demonstrated net capability of the
plant, for all fixed costs of the unit and operating costs of the unit
incurred by PSNH, which are reasonable and cost-effective for the
remaining term of the VELCO contract. In early 1998, PSNH took the
Merrimack Unit #2 facility off line, shut it down and commenced a
maintenance outage. In February, March and April of 1998, PSNH billed
VELCO for costs to complete the maintenance outage. VELCO disputes the
validity of a portion of the charges on grounds that the maintenance
performed at the unit was to extend the life of the Merrimack plant
beyond the term of the VELCO contract and that the charges in connection
with said investments were not reasonable and cost-effective for the
remaining term of the VELCO contract. As part of the settlement with NU
of the Millstone Unit #3 litigation, NU has agreed to indemnify and hold
the Company harmless from all liabilities arising from this litigation.
Cogeneration/Independent Power Qualifying Facilities ("IPPs")
A number of IPPs using hydroelectric, biomass, and refuse-burning
generation are currently producing energy that is allocated to the
Company for the benefit of its customers by operation of Vermont law.
The majority of this energy is purchased by a state appointed purchasing
agent who purchases and redistributes the power to all Vermont
utilities, for the benefit of customers, based on their pro-rata share
of total Vermont retail kilowatt-hour sales for the previous calendar
year.
As part of the Company's initiative to cut power costs and
restructure Vermont's utility industry, on August 3, 1999, the Company,
Green Mountain Power ("GMP"), Citizens Utilities and all of Vermont's 15
municipal utilities, filed a petition with the PSB requesting
modification of the contracts between the IPPs and the state appointed
purchasing agent. The petition is based on unique provisions of the
existing contracts and PSB regulations that provide for modifications
and alterations that serve the public interest. The petition outlines
seven specific elements that, if implemented, would reduce the purchase
power costs of these contracts.
On September 3, 1999, the PSB responded to the Company's petition
by opening a formal investigation in Docket No. 6270 regarding these
contracts. Shortly thereafter, Citizens Utilities, Hardwick Electric
Department and the Burlington Electric Department notified the PSB that
they were withdrawing from the petition but they will participate in the
case as a non-moving parties. In a separate VSC action brought by
several IPP's owners, GMP's full participation in this PSB proceeding
was enjoined. That injunction is now on appeal to the VSC. The
Company, the other moving utilities and the DPS have requested that the
PSB issue an order requiring GMP's full participation in the PSB
proceeding. The IPPs have also filed a related proceeding in the
Washington County Superior Court contending that the PSB rules
pertaining to IPPs, which the utilities have relied upon, in part, in
their petition before the PSB contains a so-called "scrivener's error."
At this time, it cannot be determined when the scrivener's error claim
will be resolved. In addition, proceedings are continuing in PSB Docket
No. 6270. The PSB has not established a schedule for final resolution
of this matter.
Production and Transmission
Primarily as a result of higher production fuel costs and reduced
activity with the alliance with Virginia Power, production and
transmission expenses increased $1.0 million for the second quarter of
2000 compared to the second quarter of 1999.
Production and transmission expenses for the first six months of
2000, compared to last year increased by $2.6 million, primarily related
to the above factors and a refund in 1999 related to transmission
billings to Hydro-Quebec in the first quarter of 1999.
Other Operation
Other operation expenses decreased $1.0 million and $2.4 million
for the three and six months of 2000, respectively, compared to last
year, primarily related to the increased deferral of Hydro-Quebec ice
storm arbitration costs.
Maintenance
Principally due to lower Millstone Unit #3 costs related to the
1999 power outage, maintenance expenses decreased $.7 million and $.8
million for the three and six months of 2000, respectively, compared to
the same periods in 1999.
Income Taxes
Federal and state income taxes fluctuate with the level of
pre-tax earnings in relation to permanent differences. For the second
quarter and first six months of 2000 these taxes decreased as a result
of lower pre-tax earnings.
Other Income and Deductions
Other income and deductions increased for the second quarter of
2000, primarily due to higher net earnings from non-utility subsidiary
companies mostly related to SmartEnergy's ownership share in HSS.
Interest on Long-Term Debt
In July 1999, the Company sold $75.0 million aggregate principal
amount of 8 1/8% Second Mortgage Bonds due 2004. Accordingly, interest
on long-term debt increased for the three and six months of 2000.
Other Interest Expense
Other interest expense decreased for the second quarter and six
months ending June 30, 2000 compared to same periods last year due to a
decrease in average outstanding short-term debt.
LIQUIDITY AND CAPITAL RESOURCES
The Company's liquidity is primarily affected by the level of cash
generated from operations and the funding requirements of its ongoing
construction and C&LM programs. Net cash flow provided by operating
activities generated $34.3 million and $32.9 million for the first six
months ended June 30, 2000 and 1999, respectively.
The Company ended the first six months of 2000 with cash and cash
equivalents of $54.0 million, an increase of $18.6 million from the
beginning of the year. The increase in cash for the first six months of
2000 was the result of $34.3 million provided by operating activities,
offset by $10.1 million used for investing activities and $5.6 million
used for financing activities.
Operating Activities - Net income, depreciation and deferred income
taxes and investment tax credits provided cash of $12.6 million.
Approximately $21.7 million of cash was provided by working capital and
other operating activities.
Investing Activities - Construction and plant expenditures consumed
cash of approximately $6.1 million, while $3.5 million was used for
non-utility investments.
Financing Activities - Dividends paid on common stock were $5.0
million, while preferred stock dividends were $.9 million. Long-term
debt provided $.8 million and reduction in capital lease obligations
required $.5 million.
The level of short-term borrowing fluctuates based on seasonal
corporate needs, the timing of long-term financing and market
conditions.
On July 30, 1999, the Company sold $75.0 million aggregate
principal amount of 8 1/8% Second Mortgage Bonds due 2004 at a price of
99.915%. The net proceeds of the offering were used to repay $15.0
million of outstanding loans under the Company's revolving credit
facility and are expected to be used for other general corporate
purposes relative to the Company's utility business. In addition, the
Company canceled its $40.0 million revolving credit facility.
The Company has an aggregate of $16.9 million of letters of credit
with expiration dates of May 31, 2001.
On February 2, 1999, Standard & Poor's Corporation ("Standard &
Poor's") lowered its corporate credit rating on the Company to
BBB- (triple-'B'-minus) from BBB (triple-'B'), the senior secured rating
to BBB+ (triple-'B'-plus) from A- (single-'A'-minus), and the preferred
stock rating to BB+ (double-'B' -plus) from BBB- (triple-'B'-minus).
In addition, the ratings were also placed on CreditWatch with negative
implications. On February 17, 1999, Standard & Poor's rating on the
Company's preferred stock was automatically reduced to BB (double-'B')
from BB+ (double -'B' plus) in response to a policy change in the way
Standard & Poor's rates preferred stock.
On March 28, 2000, Standard & Poor's reaffirmed that its ratings on
the Company remain on CreditWatch with negative implications, reflecting
the potentially adverse impact of pending legal and regulatory decisions
that could seriously weaken the Company's credit profile.
In this regard, Standard & Poor's had the following excerpted
comments:
"Standard & Poor's remains highly concerned about several important
events, which are expected to occur in mid- to late-2000 and could
result in significantly lower ratings. These events include the outcome
of contract renegotiations with key power suppliers, most notably
Hydro-Quebec, the arbitration related to the January 1998 ice storm, and
a Vermont Supreme Court appeal, offset in part by the pending sale of
the Vermont Yankee nuclear plant. Furthermore, if the PSB disallows the
full recovery of power costs associated with the Hydro-Quebec contract,
the utility may be required to record substantial write-offs. The
outcome of key regulatory decisions will be the principal rationale for
any rating or outlook adjustments.
CV's ratings reflect a below-average business profile, coupled with
a weak financial profile for the current ratings when adjusted for
off-balance-sheet power and transmission obligations. The utility's
business profile reflects increasingly restrictive regulation, rising
power costs, and nuclear asset exposure. This is tempered only
partially by a diverse service area economy with limited industrial
concentration, regionally competitive rates, and improving operational
efficiency."
Standard & Poor's also said "resolution of the CreditWatch listing
will depend on the Hydro-Quebec renegotiations, the arbitration related
to the January 1998 ice storm the Vermont Supreme Court appeal, and
other state and federal legal proceedings, which could be resolved in
mid- to late-2000. In addition, adequate rate relief and/or successful
mitigation of high power costs through contract renegotiations or other
methods are essential for maintaining ratings".
On February 17, 1999, Duff & Phelps Credit Rating Co.("Duff &
Phelps") placed the credit ratings of the Company on Rating Watch-Down
due to the high level of regulatory and public policy uncertainty in
Vermont and the unfavorable ruling by the United States Court of Appeals
relating to Connecticut Valley, the Company's wholly owned New Hampshire
subsidiary.
On July 16, 1999, Duff & Phelps assigned a rating of
"BBB-" (Triple-B-minus) to the Company's then proposed $75 million issue
of second mortgage bonds and lowered its rating on the Company's
preferred stock to "BB+" (Double-B-plus) from "BBB-" (Triple-B-minus)
with all ratings remaining on Rating Watch--Down.
On April 4, 2000, Duff & Phelps reaffirmed the Company's credit
ratings and has maintained the ratings on Rating Watch-Down. Duff &
Phelps had the following excerpted comments:
"The watch status reflects the continued high level of regulatory
and public policy uncertainty in Vermont and the ultimate legal and
regulatory outcome associated with the Company's wholly owned
subsidiary, Connecticut Valley, which adds risk to the Company's
financial profile going forward. Approximately $190 million of debt and
preferred securities are affected."
Duff & Phelps also said, "The Company's ratings and watch status
incorporate past negative rulings issued by the PSB regarding purchased
power costs, which have led to financial instability and uncertainty
among electric utilities in Vermont. Consequently, this uncertain
public policy environment has directly impacted CV's overall credit
quality, resulting in lower coverage ratios and reduced financial
flexibility. Positively, CV has taken initiatives to offset the
short-term financial and liquidity constraints of this regulatory
induced situation. CV's recent second mortgage issuance (July 1999)
provides the Company increased financial flexibility to meet its
upcoming mandatory debt and preferred retirements over the next few
years while a resolution to Vermont's above-market purchased power
obligations, stranded cost recovery and ultimately industry
restructuring is attained."
Current credit ratings of the Company's securities by Standard &
Poor's and Duff & Phelps remain as follows:
Standard Duff &
& Poor's(1) Phelps(2)
Corporate Credit Rating BBB- N/A
First Mortgage Bonds BBB+ BBB
Second Mortgage Bonds BBB- BBB-
Preferred Stock BB BB+
(1) All Standard and Poor's ratings are placed on "CreditWatch
with negative implications."
(2) All Duff & Phelps ratings are placed on "Rating
Watch- Down."
In 1998, Catamount, replaced its $8.0 million credit facility with
a $25.0 million revolving credit/term loan facility maturing November
2006 which provides for up to $25.0 million in revolving credit loans
and letters of credit of which $6.3 million was outstanding at June 30,
2000. This facility has a security interest in Catamount's assets.
Catamount currently has a $1.2 million letter of credit outstanding to
support certain of its obligations in connection with a debt service
requirement in the Appomattox Cogeneration project. In addition,
letters of credit for $11.0 million are outstanding in support of
construction and equity commitments for its Gauley River Power project.
SmartEnergy Water Heating Services, Inc., a wholly owned subsidiary
of SmartEnergy, has a secured $1.5 million, seven-year term loan with
Bank of New Hampshire with an outstanding balance of $1.4 million at
June 30, 2000. The interest rate is fixed at 9.50%.
Financial obligations of the Company's subsidiaries are
non-recourse to the Company.
The Company cannot assure that its business will generate
sufficient cash flow from operations or that future borrowing will be
available to the Company in an amount sufficient to enable the Company
to pay its indebtedness, including the $75.0 million second mortgage
bonds, when due or to fund its other liquidity needs. The Company's
ability to repay its indebtedness is, to a certain extent, subject to
general economic, financial, competitive, legislative, regulatory,
weather and other factors that are beyond its control. The type, timing
and terms of future financing that the Company may need will be
dependent upon its cash needs, the availability of refinancing sources
and the prevailing conditions in the financial markets. The Company
cannot guarantee that financing sources will be available to the Company
at any given time or that the terms of such sources will be favorable.
Hydro-Quebec Contract
The Company is purchasing varying amounts of power from
Hydro-Quebec under the VJO contract through 2016. Related contracts
were negotiated between the Company and Hydro-Quebec which in effect
alter the terms and conditions contained in the VJO contract, reducing
the overall power requirements and cost of the original contract.
There are specific contractual step up provisions that provide that
in the event any VJO member fails to meet its obligation under the
contract with Hydro-Quebec, the balance of the VJO participants,
including the Company, will "step up" to the defaulting party's share on
a pro-rata basis. As of December 31, 1999 the Company's VJO projected
cost obligation is approximately 47% or $1.0 billion on a nominal basis
over the term of the contract ending in 2016. The total VJO contract
obligation on a nominal basis over the term of the contract is
approximately $2.1 billion.
During January 1998, a significant ice storm affected parts of New
York, New England and the Province of Quebec, Canada. This storm
damaged major components of the Hydro-Quebec transmission system over
which power is supplied to Vermont under the VJO Power Contract with
Hydro-Quebec. This resulted in a 61-day interruption of a significant
portion of scheduled contractual energy deliveries into Vermont. The
ice storm's effect on Hydro-Quebec's transmission system caused the VJO
to examine Hydro-Quebec's overall reliability and ability to deliver
energy. On the basis of that examination, the VJO determined that
Hydro-Quebec has been and remains unable to make available capacity with
the degree of firmness required by the VJO Power Contract. That
determination has prompted the VJO to initiate an arbitration
proceeding. In the arbitration, the VJO is seeking to terminate the
contract, to recover damages associated with Hydro-Quebec's failure to
comply with the contract, and to recover capacity payments made during
the period of non-delivery.
In September 1999, an initial two weeks of hearings were held
dealing primarily with issues of contract interpretation. The second
phase of the arbitration hearings have concluded and a final decision in
the case is expected late this year or in early 2001. In accordance
with a PSB Accounting Order, the Company has deferred incremental costs
associated with this arbitration of approximately $3.9 million through
June 30, 2000. Recovery of these costs will be determined in the next
rate proceedings.
Diversification
Catamount Resources Corporation was formed for the purpose of
holding the Company's subsidiaries that invest in non-regulated business
opportunities. Catamount, a subsidiary of Catamount Resources
Corporation, invests in energy generation projects in North America and
Western Europe. Through its wholly owned subsidiaries, Catamount has
interests in seven operating independent power projects located in
Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont;
Thetford, England; Hopewell, Virginia; and Fort Dunlop, England. In
addition, Catamount has interests in a project under construction in
Summersville, West Virginia. In November 1999 Catamount created a new
subsidiary, Catamount Investment Company LLC, which will provide
additional capital for investment in new generation projects. Catamount
has partnered with CIT Group, a major equipment finance company, and
Dana Commercial Credit Corporation, the finance subsidiary of Dana
Corporation. Capital commitments from these two joint venture partners
are $60.0 million, expected to be invested over the next four years.
Catamount's after-tax earnings were $.0 million and $.3 million for the
second quarter of 2000 and 1999, respectively and $.3 million and $.9
million for the first six months of 2000 and 1999, respectively.
SmartEnergy, also a subsidiary of Catamount Resources Corporation
invests in unregulated energy and service related businesses.
SmartEnergy also has an ownership interest in HSS. Overall, SmartEnergy
incurred after-tax earnings of $.4 million and net losses of $.4 million
for the second quarter of 2000 and 1999, respectively and net losses of
$2.3 million and $.5 million for the first six months of 2000 and 1999,
respectively. HSS establishes a network of affiliate contractors who
perform home maintenance repair and improvements via membership.
SmartEnergy's investment in HSS is accounted for using the equity
method. HSS began operations in the first quarter of 1999 and is
subject to risks and challenges similar to a company in the early stage
of development. HSS' pre-tax loss for the first six months of 2000 was
$10.0 million, resulting primarily from the national rollout of HSS, of
which SmartEnergy's share was $3.7 million.
HSS began a test rollout through Sam's Club in late spring 1999.
After a successful test market, the national rollout anticipated for
year 2000 was accelerated to begin at the end of 1999. In December 1999
HSS announced that it had developed another marketing relationship with
TruServ Corporation, the cooperative entity for True Value Hardware
Stores. On March 14, 2000, HSS issued 3,500,000 shares of convertible
preferred stock. The proceeds, net of transaction costs of
approximately $32.0 million, will be used by HSS to finance the national
rollout of HSS. As a result of the sale of 50% of the ownership in HSS,
and losses that have already been incurred on the Company's investment
in HSS, the Company expects to recognize insignificant losses during the
balance of calendar year 2000. The Company's current ownership of HSS
is 37.5%.
Proposed Formation of Holding Company
In order to further prepare Central Vermont Public Service
Corporation for deregulation, on July 24, 1998, the Company filed a
petition with the PSB for permission to create a holding company that
would have as subsidiaries the Company and non-utility subsidiaries,
Catamount and SmartEnergy. The Company believes that a holding company
structure will facilitate the Company's transition to a deregulated
electricity market. The proposed holding company formation must also be
approved by Federal regulators, including the Securities and Exchange
Commission and the FERC, and by the Company's shareholders. The Company
has negotiated an agreement regarding the formation of a holding company
with the DPS. The agreement establishes a code of conduct and affiliate
transaction rules. As part of the agreement, the Company has also
agreed to not further pursue the holding company proceeding before the
PSB until additional progress is made on other restructuring
initiatives.
ELECTRIC INDUSTRY RESTRUCTURING
The electric utility industry is in a period of transition that may
result in a shift away from rate making based on cost of service and
return on equity to more market-based rates with energy sold to
customers by competing retail energy service providers. Many states,
including Vermont and New Hampshire, where the Company does business,
are exploring new mechanisms to bring greater competition, customer
choice and market influence to the industry while retaining the public
benefits associated with the current regulatory system.
Vermont
Recently, there have been three primary sources of Vermont
governmental activity in attempting to restructure the electric industry
in Vermont: (1) the Governor's Working Group, created by the Governor of
Vermont; (2) the PSB's Docket No. 6140, through which the PSB considered
restructuring proposals; (3) the PSB's Docket No. 6330, through which
the PSB is considering the establishment of policies and procedures to
govern retail competition within the Company's Vermont service
territory.
The Working Group
On July 22, 1998, the Governor of Vermont issued an Executive Order
establishing the Working Group on Vermont's Electricity Future to lead a
new effort to review the issues of potential restructuring of Vermont's
electric industry. The Working Group was created to determine how
restructuring the electric industry in Vermont could reduce both current
and long-term electric costs for all classes of Vermont electric
consumers. The Working Group was asked to provide a fact-based analysis
of the options for electric industry restructuring and the impact of
such industry changes on consumers and upon Vermont utilities. Further,
the Working Group was directed by the Governor to gather information on
and evaluate the possible consequences of the current financial status
of Vermont electric utilities.
A report was issued by the Working Group on December 18, 1998. Key
conclusions of the report were:
- The bankruptcy of Vermont electric utilities should not be viewed
as an appropriate means to reduce Vermont utilities' committed
power supply costs.
- Vermont should restructure its electric industry by moving
rapidly to retail choice whereby consumers would purchase power
directly from competing power suppliers.
- Vermont electric utilities should pursue power contract
renegotiations through payments to buy down power contracts or
buy-out power contracts. Financing for such payments should be
obtained in the capital markets after a comprehensive regulatory
process dealing with all of the elements of the restructuring of
the Vermont electric utility industry.
- The Vermont electric utilities should pursue auctions of their
power generation assets and remaining power contracts.
- Consolidation of existing electric utilities in Vermont (there
are currently 22 utilities) should be considered in order to
effect additional savings for utility customers.
The Working Group noted that by March 1, 2000, most New Englanders
outside Vermont will have a choice of their power supplier. While New
England has the highest electricity rates in the nation, electricity
costs in Vermont have been among the lowest in the region, although the
Company's rates are higher than the Vermont average. However, that
advantage is eroding as other states in New England restructure their
electric utility industries. Therefore, the Working Group noted that it
is in the interest of Vermont ratepayers to have the benefit of a
restructured electric utility industry as soon as possible.
Public Service Board Docket No. 6140
On September 15, 1998, the PSB opened Docket No. 6140 with the goal
of creating a regulatory environment and a procedural framework to call
forth, for disciplined review, proposals for reducing current and future
power costs in Vermont. The PSB intended that this proceeding define one
or more acceptable courses for power supply reform. All Vermont
utilities were made a party to the proceeding. Subsequent to the PSB's
announcement, preliminary position papers were filed and a series of
technical conferences were convened with the PSB to recommend the scope
of the investigation, potential courses for reform of Vermont's power
supply and other matters associated therewith including the
consideration of the Working Group's recommendations.
On March 3, 1999, the Company filed its Restructuring Plan, a
Working Plan to restructure a significant portion of Vermont's Electric
Utility Industry, with the PSB and parties in Docket No. 6140. The
Company's plan was a joint plan with GMP. On July 12, 1999, the PSB
issued a Status Order concluding that the objective of implementing
power supply reform may be advanced more effectively in ways other than
holding further technical conferences in this docket. Absent good
reason to hold one or more technical conferences pertinent to power
supply reform, the PSB indicated that the docket would be closed on
December 31, 1999, which action has occurred. As a companion proceeding
to its Docket No. 6140 investigation, on January 19, 1999, the PSB
issued an order opening a new contested case proceeding, Docket No.
6140-A, where it indicated that it intended to issue final, binding and
appealable orders concerning matters related to the reform and
restructuring of Vermont's electric utility industry. Initially, the PSB
notified parties that it intended proceedings in Docket No. 6140-A to
consider matters associated with the bankruptcy of one or more of the
Vermont electric utilities. After an opportunity for comment, the focus
of the proceeding was amended to consider the principles, authority and
proposals for reform of Vermont's electric power supply. This included
issues associated with the scope and extent of the Board's authority to
approve "securitization" and other financing proposed to be entered into
in connection with the buy-out or buy-down of power contracts and the
criteria to be applied by the PSB when considering voluntary utility
restructuring proposals.
By Order dated June 24, 1999 in Docket 6140-A, the PSB formally
adopted the Vermont Principles on Electric Utility Restructuring. The
Order explains that proposals to open utility franchise service areas to
retail competition, including our Restructuring Plan, will only be
approved if they can be found to satisfy the public good after due
consideration is given to each of 14 Restructuring Principles. If one or
more of the principles is not satisfied by the proposal, then the
proponent must offer justification for the deficiency and demonstrate
satisfaction of certain statutory requirements. As such, the PSB stated
that any filing proposing to open a franchise territory to retail choice
would have to be supported, at a minimum, by an explanation of how that
proposal fulfills the policy objectives established by the Vermont
Principles on Electric Utility Restructuring.
With regard to financing, no party to the investigation asked that
the PSB clarify its authority or issue a declaratory ruling concerning
the criteria to be considered when approving utility financing for the
buy-out or buy-down of committed power contracts. During the
investigation, both the Company and Green Mountain Power Corporation
asserted that anticipated refinancing approaches could be accomplished
utilizing the existing Vermont and federal legislative regime that
governs the regulation of electric utilities and that "securitization"
style financing were not presently being contemplated. Because no party
to the Docket contradicted these statements, the Board accepted our
assertions and took no further action to evaluate specific utility
financing proposals.
In contrast, Vermont Electric Power Producers, Inc.("VEPP"),
purchasing agent for the purchase of power from qualifying facilities
pursuant to PSB Rule 4.100, proposed to use administrative
securitization to finance the reform of its power purchase contracts.
However, at the request of all commenting parties, the PSB determined to
withhold judgment on the issue as to whether the PSB had jurisdiction to
authorize a VEPP financing until such time as a specific proposal was
actually filed with the PSB. In the absence of any requests for further
investigation or action to be filed within 30 days of the Docket No.
6140-A Order, the PSB indicated that this investigation would be closed,
which action has occurred. To follow up on its proposal, on June 15,
2000, VEPP filed a petition requesting that the PSB issue a declaratory
ruling confirming the authority of the PSB to issue voluntary
administrative securitization orders relative to those qualifying
facilities currently holding purchase power contract under PSB Rule
4.100. By order dated June 30, 2000 the PSB opened Docket No. 6396. A
final order in that proceeding is expected by year end.
The Company supports the Working Group recommendations described
above and believes that the restructuring of the electric industry is
essential to improve our financial position, enhance our ability to
effectively compete in a changing electric utility industry and
stabilize projected costs.
As a result, the Company is pursuing a comprehensive financial
Restructuring Plan, certain elements of which were included in the Plan
that the Company and GMP filed with the PSB in the first quarter of 1999
in connection with the proceedings in Docket No. 6140 described above.
The Company is aggressively pursuing implementation of the Restructuring
Plan which includes the following elements:
- Retail choice: voluntarily giving up the exclusive right to
supply power to the Company's present electric customers, while
retaining its rights as a distribution company, as part of a
global settlement of regulatory issues.
- Renegotiation of certain purchase power contracts: reducing the
Company's future cost of power by renegotiating power contracts,
specifically those with Hydro-Quebec and the Vermont purchasing
agent's contracts with IPPs which together represent
approximately 40% of the Company's 1998 net energy supply. The
Company may seek to finance the cost of any buy-outs or
buy-downs of power contracts through the future issuance of
securities in the capital markets.
- Contract and asset disposition: seeking to sell power purchase
contracts and generating assets, including the Company's interest
in the Vermont Yankee nuclear generating plant. On October 15,
1999, the Company and the other owners of Vermont Yankee accepted
a bid for sale of the plant to AmerGen Energy Company
("AmerGen"), which is owned by PECO Energy Company and British
Energy. This transaction will also involve taking back a
contract to purchase a portion of the power produced by this
plant. The Vermont Yankee sale needs to be approved by numerous
state and federal regulatory bodies. On November 4, 1999 the PSB
opened Docket No. 6300 to consider the issues attendant to the
approval of the sale of Vermont Yankee and approval of various
related agreements including the Company's agreement to continue
to purchase its share of the output of Vermont Yankee. A final
order in that proceeding is expected by year end.
- Cost-cutting: implementing cost-cutting measures to reduce cash
flow requirements while maintaining safety and reliability
standards.
- Holding company: establishing a holding company in order to
further prepare the Company for deregulation.
- Industry consolidation: evaluating possible consolidations with
other Vermont electric distribution companies.
- Regulatory settlement: seeking a comprehensive regulatory
settlement that leads to long-term financial stability.
- Energy efficiency activities: creating a state sponsored
"energy-efficiency utility" to take over most system-wide
energy-efficiency services for electric customers. On
September 30, 1999, the PSB issued a final Order approving a
Memorandum of Understanding between the Company, the Vermont
Department of Public Service, all other Vermont electric utility
companies and other interested parties that calls for the
establishment of the energy-efficiency utility and provides for
its funding via a separate stated Energy Efficiency Charge. As
of March 2000, system-wide energy-efficiency services are
provided to the Company's customers by Efficiency Vermont, the
contractor selected by the PSB to serve as the energy-efficiency
utility.
The Company believes that implementation of its Restructuring Plan
is a critical element to improving its future financial performance and
to providing its customers with more stable electric rates and the
continuation of efficient and reliable electric service. The key
contingency of the Company's Restructuring Plan is regulatory approval
of a rate schedule that will allow the Company to recover the costs of
the restructuring. If the financial restructuring described in this
section is completed in conjunction with the deregulation of Vermont's
electric industry described in "Electric Industry Restructuring," the
Company anticipates that its utility financial performance and prospects
will improve significantly.
Public Service Board Docket No. 6330
On November 23, 1999, the Company and GMP (together the
"Companies") filed a joint Petition and Supporting Materials with the
PSB asking that the PSB open an investigation to establish retail access
policies and procedures to resolve issues that must be decided to
implement the Companies' Restructuring Plan. Specifically, the Petition
requests that the PSB issue such orders and approvals as are necessary
or advisable to:
1) permit the Companies to suspend their provision of power supply
Services ("Generation Service") to customers located within
their respective service territories;
2) permit the Companies to amend their service tariff obligations
to clarify that they retain their exclusive service franchises
as providers of electric delivery services ("Delivery Service")
to customers within their respective service territories;
3) permit the Companies to implement a Retail Open Access Tariff
("R-OAT") that enables customers located within the Companies'
respective service territories to choose their power supplier
from an array of approved energy service providers ("ESP"),
and to purchase Generation Service from such ESPs at
market-determined prices;
4) select through a competitive bidding process an ESP or ESPs to
deliver "Default Service" for energy to customers located
within the Companies' service territories that do not otherwise
have an arrangement with an ESP for the Provision of Generation
Service;
5) select through a competitive bidding process an ESP or ESPs to
deliver "Transition Service" for energy to customers located
within the Companies' service territories; and
6) approve revisions and modifications to the Companies' tariffs
to implement voluntary retail access within the Companies'
respective service territories as provided for pursuant to this
Petition.
The consent to retail access within the Companies' service areas
established by the Petition is voluntary and conditional. Pursuant to
the Petition, the Companies' consent to customer choice and retail
competition is expressly conditioned upon approval of all elements of
the Companies' Restructuring Plan including the approval of any proposed
mitigation measures to reduce power costs and financing measures related
thereto, and a mechanism to recover the costs rendered stranded on
account of the move to retail access and customer choice.
On January 14, 2000, the PSB opened Docket No. 6330 to consider the
issues raised by the Companies' petition. In its opening Order, the
Board states:
"The scope of this investigation is intended to address many of
the more detailed aspects of retail open access. While current
law may not permit this Board to require retail open access of
Vermont utilities, the companies are clearly able to open their
service territories on a voluntary basis. Whether retail open
access is established on a voluntary basis through existing
statutes or through revised legislation, there are many technical
issues to be resolved. This investigation will serve to advance
many aspects of issues surrounding retail open access."
An initial pre-hearing conference was held in this investigation on
January 31, 2000. The parties to Docket No. 6330 have agreed to
consider the Companies proposal in a proceeding consisting of two
phases. In Phase I parties will identify the scope and extent of
consensus on docket issues (Module 1) and attempt to negotiate
agreements on matters where consensus does not initially emerge (Module
2). In Phase II, parties will litigate unresolved issues. At this
time, it is premature to predict the date upon which a final PSB
resolution of the matters raised in this investigation will be decided
although, the Companies proposed an initial start date for retail
competition of September 1, 2001, provided that all of the elements of
the joint Restructuring Plan are completed by that time.
Competition and Risk Factors
If retail competition is implemented in Vermont or New Hampshire,
the Company is unable to predict the impact of this competition on its
revenues, the Company's ability to retain existing customers with
respect to their power supply purchases and attract new customers or the
margins that will be realized on retail sales of electricity, if any
such sales are sought. The Company expects its power distribution and
transmission service to its customers to continue on an exclusive basis
subject to continuing economic regulation.
Historically, electric utility rates have been based on a utility's
costs. As a result, electric utilities are subject to certain
accounting standards that are not applicable to other business
enterprises in general. SFAS No. 71 requires regulated entities, in
appropriate circumstances, to establish regulatory assets and
liabilities, and thereby defer the income statement impact of certain
costs and revenues that are expected to be realized in future rates.
As described in Note 1 of Notes to Consolidated Financial
Statements, the Company believes it currently complies with the
provisions of SFAS No. 71 for both its regulated Vermont service
territory and FERC regulated wholesale businesses. In the event the
Company determines that it no longer meets the criteria for following
SFAS No. 71, the accounting impact would be an extraordinary, non-cash
charge to operations of approximately $56.4 million on a pre-tax basis
as of June 30, 2000. Criteria that give rise to the discontinuance of
SFAS No. 71 include (1) increasing competition that restricts the
Company's ability to establish prices to recover specific costs and (2)
a significant change in the manner in which rates are set by regulators
from cost-based regulation to another form of regulation.
The Securities and Exchange Commission has questioned the ability
of certain utility companies continuing the application of SFAS No. 71
where legislation provides for the transition to retail competition.
Deregulation of the price of electricity issues related to the
application of SFAS No. 71 and 101, as to when and how to discontinue
the application of SFAS No. 71 by utilities during transition to
competition has been referred to the Financial Accounting Standards
Board's Emerging Issues Task Force ("EITF").
The EITF has reached a tentative consensus, and no further
discussion is planned, that regulatory assets should be assigned to
separable portions of the Company's business based on the source of the
cash flows that will recover those regulatory assets. Therefore, if the
source of the cash flows is from a separable portion of the Company's
business that meets the criteria to apply SFAS No. 71, those regulatory
assets should not be written off under SFAS No. 101, "Accounting for the
Discontinuation of Application of SFAS No. 71," but should be assessed
under paragraph 9 of SFAS No. 71 for realizability.
SFAS No. 121, "Accounting for the Impairment of Long Lived Assets
and for Long-Lived Assets to Be Disposed Of," which was adopted by the
Company on January 1, 1996, requires that any assets, including
regulatory assets, that are no longer probable of recovery through
future revenues, be revalued based upon future cash flows. SFAS No. 121
requires that a rate-regulated enterprise recognize an impairment loss
for the amount of costs excluded from recovery. As of December 31,
1999, based upon the regulatory environment within which the Company
currently operates, SFAS No. 121 did not have an impact on the Company's
financial position or results of operations. Competitive influences or
regulatory developments may impact this status in the future.
Because the Company is unable to predict what form possible future
restructuring legislation will take, it cannot predict if or to what
extent SFAS Nos. 71 and 121 will continue to be applicable in the
future. In addition, if the Company is unable to mitigate or otherwise
recover stranded costs that could arise from any potentially adverse
legislation or regulation, the Company would have to assess the
likelihood and magnitude of losses incurred under its power contract
obligations.
As such, the Company cannot predict whether any restructuring
legislation enacted in Vermont or New Hampshire, once implemented, would
have a material adverse effect on the Company's operations, financial
condition or credit ratings. However, the Company's failure to recover
a significant portion of its purchased power costs, would likely have a
material adverse effect on the Company's results of operations, cash
flows, ability to obtain capital at competitive rates and ability to
exist as a going concern. It is possible that stranded cost exposure
before mitigation could exceed the Company's current total common stock
equity.
Recent Accounting Pronouncements
In June 1998, the FASB issued SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities. In June 1999, the FASB
issued Statement No. 137, Accounting for Derivative Instruments and
Hedging Activities -- Deferral of the Effective Date of SFAS No. 133 and
in June 2000, issued SFAS No. 138, Accounting for Certain Derivative
Instruments and Certain Activities, an amendment of FASB Statement No.
133. These Statements establish accounting and reporting standards
requiring that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded in the balance
sheet as either an asset or liability measured at its fair value. These
Statements require that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting
criteria are met. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged
item in the income statement, and requires that a company must formally
document, designate, and assess the effectiveness of transactions that
receive hedge accounting.
SFAS No. 133, as amended, is effective for fiscal years beginning
after June 15, 2000. A company may also implement this Statement as of
the beginning of any fiscal quarter after issuance (that is, fiscal
quarters beginning June 16, 1998 and thereafter). SFAS No. 133 cannot
be applied retroactively. SFAS No. 133 must be applied to (a)
derivative instruments and (b) certain derivative instruments embedded
in hybrid contracts. With respect to hybrid instruments, a company may
elect to apply SFAS 133, as amended, to (1) all hybrid contracts, (2)
only those hybrid instruments that were issued, acquired, or
substantively modified after December 31, 1997, or (3) only those hybrid
instruments that were issued, acquired, or substantively modified after
December 31, 1998. The Company has not yet quantified the impacts of
adopting SFAS No. 133 on the financial statements. The Company has
organized an implementation team and established a schedule for
implementation by January 1, 2000, as required by SFAS 133, as amended.
Forward Looking Statements
This document contains statements that are forward looking. These
statements are based on current expectations that are subject to risks
and uncertainties. Actual results will depend, among other things, upon
general economic and business conditions, weather, the actions of
regulators, including the outcome of the litigation involving
Connecticut Valley before the FERC and the Court and the Company's
pending rate case before the PSB and associated appeal to the Vermont
Supreme Court, as well as other factors which are described in further
detail in the Company's filings with the Securities and Exchange
Commission. The Company cannot predict the outcome of any of these
proceedings or other factors.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
On August 7, 1997, the Company and eight other non-operating owners
of Millstone Unit #3 ("Unit #3")filed a demand for arbitration with
Connecticut Light and Power Company and Western Massachusetts Electric
Company, both NU affiliates, and lawsuits against NU and its trustees.
The arbitration and lawsuits seek to recover costs associated with
replacement power, operation and maintenance costs and other costs
resulting from the shutdown of Unit #3. The non-operating owners claim
that NU and two of its wholly owned subsidiaries failed to comply with
NRC's regulations, failed to operate the facility in accordance with
good operating practice and attempted to conceal their activities from
the non-operating owners and the NRC.
On July 27, 2000, the Company executed a settlement agreement with
NU, resolving all issues asserted by the Company in the arbitration and
lawsuits. The settlement will become effective upon the approval of the
Company's withdrawal from these actions.
Except as otherwise described under Management's Discussion and
Analysis of Financial Condition and Results of Operations, Item 2, there
are no other material pending legal proceedings, other than ordinary
routine litigation incidental to the business, to which the company or
any of its subsidiaries is a party or to which any of their property is
subject.
Items 2 and 3 and 4: None.
Item 5. Other Information.
(a) On May 22, 2000, John J. Holtman joined the Company as Vice
President and Controller.
Item 6. Exhibits and Reports on Form 8-K.
(a) List of Exhibits
10. Material Contracts
10.8.8 Amendment No. 8, dated November 17, 1999
Power Contract between the Company and Vermont
Yankee
10.8.9 Amendment No. 9, Dated November 17, 1999
Power Contract between the Company and Vermont
Yankee
10.27.6 1987 Supplementary Power Contract, dated
April 1, 1987
Power Contract between the Company and
Connecticut Yankee
10.27.7 1996 Amendatory Agreement, dated
December 1, 1996
Power Contract between the Company and
Connecticut Yankee
10.27.8 2000 Amendatory Agreement, dated May, 2000
Power Contract between the Company and
Connecticut Yankee
27. Financial Data Schedule
(b) Item 5. Report on Form 8-K for the second quarter
2000 - None
<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 /s/ Francis J. Boyle
Francis J. Boyle, Senior Vice President, Principal
Financial Officer and Treasurer
By /s/ John J. Holtman
John J. Holtman, Vice President and Controller,
Principal Accounting Officer
Dated August 11, 2000
