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 September 30, 1998
TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to _______
Commission file number 1-8222
Central Vermont Public Service Corporation
(Exact name of registrant as specified in its charter)
Incorporated in Vermont 03-0111290
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
77 Grove Street, Rutland, Vermont 05701
(Address of principal executive offices) (Zip Code)
802-773-2711
(Registrant's telephone number, including area code)
__________________________________________________________________________
(Former name, former address and former fiscal year, if changed since last
report)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X No _____
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date. As of October 31, 1998
there were outstanding 11,457,876 shares of Common Stock, $6 Par Value.
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q
Table of Contents
Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statement of Income and Retained Earnings
for the three and nine months ended September 30, 1998
and 1997 3
Consolidated Balance Sheet as of September 30, 1998 and
December 31, 1997 4
Consolidated Statement of Cash Flows for the nine months
ended September 30, 1998 and 1997 5
Notes to Consolidated Financial Statements 6-12
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 13-30
PART II. OTHER INFORMATION 31
SIGNATURES 32
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENT OF INCOME AND RETAINED EARNINGS
(Dollars in thousands, except per share amounts)
(Unaudited)
Three Months Ended Nine Months Ended
September 30 September 30
1998 1997 1998 1997
------- ------- -------- --------
<S> <C> <C> <C> <C>
Operating Revenues $69,522 $67,990 $219,886 $221,926
------- ------- -------- --------
Operating Expenses
Operation
Purchased power 42,196 40,114 127,784 121,415
Production and transmission 5,925 6,134 17,279 17,421
Other operation 9,955 9,762 32,808 30,445
Maintenance 3,767 4,187 11,421 10,913
Depreciation 4,145 4,135 12,603 12,824
Other taxes, principally property taxes 2,779 2,394 8,623 8,100
Taxes on income (176) 86 1,837 6,375
------- ------- -------- --------
Total operating expenses 68,591 66,812 212,355 207,493
------- ------- -------- --------
Operating Income 931 1,178 7,531 14,433
------- ------- -------- --------
Other Income and Deductions
Equity in earnings of affiliates 808 790 2,384 2,467
Allowance for equity funds during
construction 13 9 41 53
Other income, net 741 3,829 1,673 7,575
Provision for income taxes (62) (1,126) - (2,157)
------- ------- -------- --------
Total other income and deductions, net 1,500 3,502 4,098 7,938
------- ------- -------- --------
Total Operating and Other Income 2,431 4,680 11,629 22,371
Net Interest Expense 2,660 2,615 7,919 7,842
------- ------- -------- --------
Net Income (Loss) Before Extraordinary
Credit (229) 2,065 3,710 14,529
Extraordinary Credit Net of Taxes - - 873 -
------- ------- -------- --------
Net Income (Loss) (229) 2,065 4,583 14,529
Retained Earnings at Beginning of Period 74,646 77,983 75,841 74,137
------- ------- -------- --------
Cash Dividends Declared
Preferred stock 486 507 1,459 1,521
Common stock 48 (21) 5,082 7,583
------- ------- -------- --------
Total dividends declared 534 486 6,541 9,104
------- ------- -------- --------
Retained Earnings at End of Period $73,883 $79,562 $ 73,883 $ 79,562
======= ======= ======== ========
Earnings (Losses) Available For
Common Stock $ (715) $ 1,558 $ 3,124 $ 13,008
Average Shares of Common Stock
Outstanding 11,448,585 11,423,401 11,432,844 11,470,643
Basic and Diluted Share of Common Stock:
Earnings (losses) before extraordinary
credit $(.06) $ .14 $.19 $1.13
Extraordinary credit - - .08 -
----- ----- ---- -----
Earnings (Losses) Per Basic and Diluted
Share of Common Stock $(.06) $ .14 $.27 $1.13
===== ===== ==== =====
Dividends Paid Per Share of Common Stock $.22 $.22 $.66 $.66
The accompanying notes are an integral part of these consolidated financial statements.
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED BALANCE SHEET
(Dollars in thousands)
September 30 December 31
1998 1997
------------ -----------
<S> <C> <C>
Assets
Utility Plant, at original cost $462,635 $461,482
Less accumulated depreciation 161,689 151,250
-------- --------
300,946 310,232
Construction work in progress 17,422 10,450
Nuclear fuel, net 847 964
-------- --------
Net utility plant 319,215 321,646
-------- --------
Investments and Other Assets
Investments in affiliates, at equity 26,144 26,495
Non-utility investments 36,022 33,736
Non-utility property, less accumulated depreciation 2,979 2,894
-------- --------
Total investments and other assets 65,145 63,125
-------- --------
Current Assets
Cash and cash equivalents 10,154 16,506
Special deposits 422 404
Accounts receivable, less allowance for uncollectible
accounts ($1,975 in 1998 and $1,946 in 1997) 21,933 23,166
Unbilled revenues 11,067 18,951
Materials and supplies, at average cost 3,890 3,779
Prepayments 4,781 1,464
Other current assets 5,509 4,970
-------- --------
Total current assets 57,756 69,240
-------- --------
Regulatory Assets 70,045 73,209
-------- --------
Other Deferred Charges 5,020 4,720
-------- --------
Total Assets $517,181 $531,940
======== ========
Capitalization and Liabilities
Capitalization
Common stock, $6 par value, authorized
19,000,000 shares; outstanding 11,785,848 shares $ 70,715 $ 70,715
Other paid-in capital 45,312 45,295
Treasury stock (327,972 shares and 362,447 shares,
respectively, at cost) (4,277) (4,728)
Retained earnings 73,883 75,841
-------- --------
Total common stock equity 185,633 187,123
Preferred and preference stock 8,054 8,054
Preferred stock with sinking fund requirements 18,000 19,000
Long-term debt 108,834 93,099
Long-term lease arrangements 16,412 17,223
-------- --------
Total capitalization 336,933 324,499
-------- --------
Current Liabilities
Short-term debt - 12,650
Current portion of long-term debt and preferred stock 21,521 24,271
Accounts payable 5,719 4,609
Accounts payable - affiliates 9,922 12,441
Accrued income taxes - 6,631
Dividends declared 486 2,513
Nuclear decommissioning costs 6,012 6,010
Other current liabilities 18,375 21,646
-------- --------
Total current liabilities 62,035 90,771
-------- --------
Deferred Credits
Deferred income taxes 56,152 53,996
Deferred investment tax credits 6,927 7,222
Nuclear decommissioning costs 24,722 28,947
Other deferred credits 30,412 26,505
-------- --------
Total deferred credits 118,213 116,670
-------- --------
Total Capitalization and Liabilities $517,181 $531,940
======== ========
The accompanying notes are an integral part of these consolidated financial statements.
</TABLE>
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)
(Unaudited)
Nine Months Ended
September 30
1998 1997
------- -------
<S> <C> <C>
Cash Flows Provided (Used) By
Operating Activities
Net income $ 4,583 $14,529
Adjustments to reconcile net income to net cash
provided by operating activities
Extraordinary credit (1,294) -
Equity in earnings of affiliates (2,383) (2,467)
Dividends received from affiliates 2,595 2,316
Equity in earnings of non-utility investments (5,094) (3,905)
Distribution of earnings from non-utility
investments 2,953 2,935
Depreciation 12,603 12,824
Deferred income taxes and investment tax credits 2,427 (691)
Allowance for equity funds during construction (41) (53)
Net deferral and amortization of nuclear refueling
replacement energy and maintenance costs (2,838) 4,045
Amortization of conservation and load management
costs 4,226 5,264
Gain on sale of investment - (2,891)
Gain on sale of property - (2,095)
Decrease in accounts receivable and unbilled
revenues 9,485 12,207
Increase (decrease) in accounts payable (941) (2,043)
Increase (decrease) in accrued income taxes (9,606) (1,316)
Change in other working capital items (4,411) 3,027
Other, net 3,768 (4,684)
------- -------
Net cash provided by operating activities 16,032 37,002
------- -------
Investing Activities
Construction and plant expenditures (11,550) (10,742)
Deferred conservation & load management expenditures (1,857) (1,065)
Return of capital 140 140
Proceeds from sale of investment - 3,750
Proceeds from sale of property - 2,624
Non-utility investments (102) (777)
Special deposits - 2,284
Other investments, net (234) 74
------- -------
Net cash used for investing activities (13,603) (3,712)
------- -------
Financing Activities
Sale (repurchase) of common stock 451 (1,072)
Short-term debt, net (650) (5,764)
Long-term debt, net (15) -
Common and preferred dividends paid (8,513) (9,103)
Other (54) -
------- -------
Net cash used for financing activities (8,781) (15,939)
------- -------
Net Increase (Decrease) in Cash and Cash Equivalents (6,352) 17,351
Cash and Cash Equivalents at Beginning of Period 16,506 6,365
------- -------
Cash and Cash Equivalents at End of Period $10,154 $23,716
======= =======
Supplemental Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) $ 5,534 $ 5,017
Income taxes (net of refunds) $ 9,940 $10,398
The accompanying notes are an integral part of these consolidated financial statements.
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 30, 1998
Note 1 - Accounting Policies
The Company's significant accounting policies are described in Note 1 of
Notes to Consolidated Financial Statements included in its 1997 Annual Report
on Form 10-K filed with the Securities and Exchange Commission. For interim
reporting purposes, the Company follows these same basic accounting policies
but considers each interim period as an integral part of an annual period.
See Note 3 below for detail in regard to a Court Order issued on April 9, 1998
by the United States Court for the District of New Hampshire, sitting in
Rhode Island (Court) which again qualifies Connecticut Valley Electric Company
Inc. (Connecticut Valley), the Company's New Hampshire subsidiary, to prepare
its financial statements in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71.
RECLASSIFICATION Certain reclassifications have been made to prior year
Consolidated Financial Statements to conform with the 1998 presentation.
The financial information included herein is unaudited; however, such
information reflects all adjustments (consisting of normal recurring accruals)
which are, in the opinion of management, necessary for a fair statement of
results for the interim periods.
Note 2 - Environmental
The Company is engaged in various operations and activities which subject
it to inspection and supervision by both federal and state regulatory
authorities including the United States Environmental Protection Agency (EPA).
It is Company policy to comply with all environmental laws. The Company has
implemented various procedures and internal controls to assess and assure
compliance. If non-compliance is discovered, corrective action is taken.
Based on these efforts and the oversight of those regulatory agencies having
jurisdiction, the Company believes it is in compliance, in all material
respects, with all pertinent environmental laws and regulations.
Company operations occasionally result in unavoidable, inadvertent
releases of regulated substances or materials, for example the rupture of a
pole mounted transformer, or a broken hydraulic line. Whenever the Company
learns of such a release, the Company responds in a timely fashion and in a
manner that complies with all federal and state requirements. Except as
discussed in the following paragraphs, the Company is not aware of any
instances where it has caused, permitted or suffered a release or spill on or
about its properties or otherwise which is likely to result in any material
environmental liabilities to the Company.
The Company is an amalgamation of more than 100 predecessor companies.
Those companies engaged in various operations and activities prior to being
merged into the Company. At least two of these companies were involved in the
production of gas from coal to sell and distribute to retail customers at
three different locations. These activities were discontinued by the Company
in the late 1940's or early 1950's. The coal gas manufacturers, other
predecessor companies, and the Company itself may have engaged in waste
disposal activities which, while legal and consistent with commercially
accepted practices at the time, may not meet modern standards and thus
represent potential liability.
The Company continues to investigate, evaluate, monitor and, where
appropriate, remediate contaminated sites related to these historic
activities. The Company's policy is to accrue a liability for those sites
where costs for remediation, monitoring and other future activities are
probable and can be reasonably estimated. As part of that process, the
Company also researches the possibility of insurance coverage that could
defray any such remediation expenses. For related information see Part II
Item 1, Legal Proceedings below.
CLEVELAND AVENUE PROPERTY The Company's Cleveland Avenue property located in
the City of Rutland, Vermont, a site where one of its predecessors operated a
coal-gasification facility and later the Company sited various operations
functions. Due to the presence of coal tar deposits and Polychlorinated
Biphenyl (PCB) contamination and uncertainties as to potential off-site
migration of those contaminants, the Company conducted studies in the late
1980's and early 1990's to determine the magnitude and extent of the
contamination. After completing its preliminary investigation, the Company
engaged a consultant to assist in evaluating clean-up methodologies and
provide cost estimates. Those studies indicated the cost to remediate the
site would be approximately $5 million. This was charged to expense in the
fourth quarter of 1992. Site investigation continued over the next several
years.
In January of 1995, the Company was formally contacted by the EPA asking
for written consent to conduct a site evaluation of the Cleveland Avenue
property. That evaluation has been completed. The Company does not believe
the EPA's evaluation changes its potential liability so long as the State
remains satisfied that reasonable progress continues to be made in remediating
the site and retains oversight of the process.
In 1995, as part of that process, the Company's consultant completed its
risk assessment report and submitted it to the State of Vermont for review.
The State generally agreed with that assessment but expressed a number of
concerns and directed the Company to collect some additional data. The
Company has addressed almost all of the concerns expressed by the State and
continues to work with the State in a joint effort to develop a mutually
acceptable solution.
The Company selected a consulting/engineering firm to collect the
additional data requested by the State and develop and implement a remediation
plan for the site. That firm has begun work at the site. It has collected
the additional data requested by the State and will use all the data gathered
to date to formulate a comprehensive remediation plan. The additional data
gathered to date has not caused the Company to alter its original estimate of
the likely cost of remediating the site.
BRATTLEBORO MANUFACTURED GAS FACILITY From the early to late 1940's, the
Company owned and operated a manufactured gas facility in Brattleboro,
Vermont. The Company received last month a letter from the State of
New Hampshire asking the Company to conduct a scoping study in and around the
site of the former facility. The Company is in the process of responding to
the State's request. The Company's response will include the identification of
a qualified consultant to do the scoping study and a search for other
Potential Responsible Parties (PRPs). At this time the Company has not
finalized an estimate of its potential liability at this site.
PCB, INC. In August 1995, the Company received an Information Request from
the EPA pursuant to a Superfund investigation of two related sites, located in
Kansas and in Missouri (the Sites). During the mid-1980's, these Sites,
operated by PCB Treatment, Inc., received materials containing PCBs from
hundreds of sources, including the Company. According to the EPA, more than
1,200 parties have been identified as PRPs. The Company has complied with the
information request and will monitor EPA activities at the Sites. In
December 1996, the Company received an invitation to join a PRP steering
committee. The Company has not yet decided whether joining that committee
would be in its best interest. That committee has estimated the Company's pro
rata share of the waste sent to the Sites to be .42%. The committee estimates
that the Sites' remediation will cost between $5 million and $40 million.
Based on this information, the Company does not believe that the Sites
represent the potential for a material adverse effect on its financial
condition or results of operations.
PARKER LANDFILL AND THE TRAFTON-HOISINGTON LANDFILL The Company has had no
involvement with these sites for over five years. Additional information on
these sites is available in the Company's Annual Report on Form 10-K.
The Company is not subject to any pending or threatened litigation with
respect to any other sites that have the potential for causing the Company to
incur material remediation expenses, nor has the EPA or other federal or state
agency sought contribution from the Company for the study or remediation of
any such sites.
In 1996, the Company filed a lawsuit in federal court against a number of
insurance companies. In its complaint, the Company alleged that general
liability policies issued by the insurers provide coverage for all expenses
incurred or to be incurred by the Company in conjunction with, among others,
the Cleveland Avenue Property. Settlements were reached with all of the
defendants. The settlements varied with respect to the scope of the release
granted by the Company. Due to the uncertainties associated with the actual
clean-up costs, no income has been recognized, instead, the proceeds have been
applied to the environmental reserve.
Note 3 - Retail Rates
Vermont: The Company's practice of reviewing costs periodically will
continue and rate increases will be requested when warranted. The Company
filed for a 6.6%, or $15.4 million per annum, general rate increase on
September 22, 1997 to become effective June 6, 1998 to offset increasing costs
of providing service. Approximately $14.3 million or 92.9% of the rate
increase request is to recover scheduled contractual increases in the cost of
power the Company purchases from Hydro-Quebec.
At the same time, the Company also filed a request to eliminate the
winter-summer rate differential and price electricity the same year-round.
The change would be revenue-neutral within classes of customers and overall.
Over time, customers would see a leveling off of rates so they would pay the
same per kilowatt-hour during the winter and summer months.
Several parties in the Company's rate case sought to challenge the
Company's decision in 1991 to "lock-in" its participation in its power
purchase agreement with Hydro-Quebec as one of 14 members of the Vermont Joint
Owners () claiming that the decision of the Company to commit to the power
contract in 1991 was imprudent and that power now purchased pursuant to that
agreement is not "used and useful." The parties have also claimed that the
Company has not met a condition of the Vermont Public Service Board's (PSB)
prior approval of the contract, requiring that the Company obtain all cost
effective Demand Side Management. In response, the Company filed a motion
asking the PSB to rule that any prudence and used and useful issues were
resolved in prior proceedings and that the PSB is precluded from again trying
the Company on those issues.
On April 17, 1998, the PSB issued an order generally denying the
Company's motion. Given the fact that the PSB had recently severely penalized
another member, Green Mountain Power Corporation, in an Order dated
February 27, 1998, after finding that its decision to lock-in the Hydro-Quebec
contract was imprudent and the power purchased pursuant to that lock-in was
not used and useful, the Company concluded that it was necessary to have the
so-called preclusion issue reviewed by the Vermont Supreme Court (VSC) before
the PSB issues a final order in the Company's current rate case. As such, the
Company and other parties requested that the PSB consent to the filing of an
interlocutory appeal of the PSB's decision and to a stay of the rate case
pending review by the VSC. The Company further agreed to toll the statutory
period of time in which the PSB must act on a rate request, while the matter
is in appeal.
The appeal and associated stay of the rate case significantly delayed the
date that new rates would have otherwise taken effect. As a result, the
Company's earnings prospects for 1998 will be adversely affected.
In an effort to mitigate eroding earnings and cash flow prospects during
the Vermont Supreme Court review process, on June 12, 1998 the Company filed
with the PSB a request for a 10.7% rate increase ($24.7 million of annualized
revenues) effective March 1, 1999. This rate case proceeding overlaps the
6.6% rate increase request referenced above that is now stayed pending a
review on the so-called preclusion issue by the VSC.
On October 27, 1998, the Company reached an agreement with the Vermont
Department of Public Service (DPS) regarding the 10.7% rate increase request.
The agreement, if approved by the PSB, provides for a temporary rate increase
in the Company's Vermont retail rates of 4.7% or $10.9 million on an
annualized basis beginning with service rendered January 1, 1999. The
temporary rate increase is subject to adjustment upon future resolution of the
Hydro-Quebec Contract issues presently before the VSC.
The agreement incorporates a disallowance of approximately $7.4 million
for the Company's purchased power costs under the Hydro-Quebec Contract while
the VSC reviews the PSB denial of the Company's claim that the PSB is
precluded from again trying the Company on certain Hydro-Quebec Contract
issues discussed above. Upon approval of the agreement by the PSB, the
Company will record a charge of approximately $7.4 million on a pre-tax basis
for disallowed purchased power expenses. The Company anticipates the PSB's
decision on the rate increase agreement during the fourth quarter of 1998 and
a resolution of the Hydro-Quebec Contract issues by the end of 1999.
If the Company receives an unfavorable ruling from the VSC, and the
methodology used to determine the temporary Hydro-Quebec disallowance is
continued for the duration of the Hydro-Quebec Contract, approximately
$205.0 million of power costs to be incurred under that contract would not be
recoverable in rates. Such a result would jeapordize the Company's ability to
continue as a going concern.
New Hampshire: On November 26, 1997, Connecticut Valley filed a request
with the New Hampshire Public Utilities Commission (NHPUC) to increase the
Fuel Adjustment Clause (FAC), Purchased Power Cost Adjustment (PPCA) and
short-term energy purchase rates effective on or after January 1, 1998.
In an Order dated December 31, 1997, the NHPUC directed Connecticut
Valley to freeze its current FAC and PPCA rates (other than short-term rates
to be paid to certain Qualifying Facilities) effective January 1, 1998, on a
temporary basis pending a hearing to determine: 1) the appropriate proxy for a
market price that Connecticut Valley could have obtained if it had terminated
its wholesale contract with the Company; 2) the implications of allowing
Connecticut Valley to pass on to its customers only that market price; and
3) whether the NHPUC's final determination on the FAC and PPCA rates should be
reconciled back to January 1, 1998 or some other date.
On January 19, 1998, Connecticut Valley and the Company filed with the
Federal District Court (Court) for a temporary restraining order to maintain
the status quo ante by staying the NHPUC Order of December 31, 1997 and
preventing the NHPUC from taking any action that (i) compromises cost-based
rate making for Connecticut Valley; (ii) interferes with the Federal Energy
Regulatory Commission's (FERC) exclusive jurisdiction over the Company's
pending application to recover wholesale stranded costs upon termination of
its wholesale power contract with Connecticut Valley; or (iii) prevents
Connecticut Valley from recovering through retail rates the stranded costs and
purchased power costs that it incurs pursuant to its FERC-authorized wholesale
rate schedule with the Company.
On February 23, 1998, the NHPUC announced in a public meeting that it
reaffirmed its finding of imprudence and designated a proxy market price for
power at 4 cents per kWh in lieu of the actual costs incurred pursuant to the
wholesale power contract with the Company. In addition, the NHPUC indicated,
subject to certain conditions which were unacceptable to the companies, that
it would permit Connecticut Valley to maintain its current rates pending a
decision in Connecticut Valley's appeal of the NHPUC Order to the
New Hampshire Supreme Court.
Based on the December 31, 1997 NHPUC Order as well as the NHPUC's
February 23, 1998 announcement, which resulted in the establishment of
Connecticut Valley's rates on a non cost-of-service basis, Connecticut Valley
no longer qualified, as of December 31, 1997, for the application of SFAS
No. 71. As a result, Connecticut Valley wrote-off all of its regulatory
assets associated with its New Hampshire retail business for the year ended
December 31, 1997. This write-off amounted to approximately $1.2 million on a
pre-tax basis. In addition, Connecticut Valley recorded a $5.5 million
pre-tax loss as of December 31, 1997 under SFAS No. 5, "Accounting for
Contingencies," representing Connecticut Valley's estimated loss on power
contracts for the twelve months following December 31, 1997.
On March 20, 1998, the NHPUC issued an order which affirms, clarifies and
modifies various generic policy statements including the reaffirmation to
establish rates on the basis of a regional average announced previously in its
February 28, 1997 Final Plan. The March 20, 1998 order also addressed all
outstanding motions for rehearings or clarification relative to the policies
or legal positions articulated in the Final Plan and removed the stay covering
the Company's interim stranded cost order of April 7, 1997. In addition, the
March 20, 1998 Order imposed various compliance filing requirements.
On April 3, 1998, the Court held a hearing on the Companies' motion for a
Temporary Restraining Order (TRO) and Preliminary Injunction against the NHPUC
at which time both the Companies and the NHPUC presented arguments. In an
oral ruling from the bench, and in a written order issued on April 9, 1998,
the Court concluded that the Companies had established each of the
prerequisites for preliminary injunctive relief and directed and required the
NHPUC to allow Connecticut Valley to recover through retail rates all costs
for wholesale power requirements service that Connecticut Valley purchases
from the Company pursuant to its FERC-authorized wholesale rate schedule
effective January 1, 1998 until further court order. Connecticut Valley has
received an order from the NHPUC authorizing retail rates to recover such
costs beginning in May 1998. On April 14, 1998, the NHPUC filed a notice of
appeal and a motion for a stay of the Court's preliminary injunction. The
NHPUC's request for a stay was denied.
Also, on April 3, 1998, the Court indicated its earlier TRO enjoining the
NHPUC's restructuring orders applied to Connecticut Valley and prohibits the
enforcement of the restructuring orders until the Court conducts a
consolidated hearing and rules on the requests for permanent injunctive relief
by plaintiff Public Service Company of New Hampshire (PSNH) and the other
utilities that have been allowed to intervene in these proceedings, including
the Company and Connecticut Valley. The plaintiffs-intervenors thereafter
filed a motion asking the Court to extend its stay of action by the NHPUC to
implement restructuring and to make clear that the stay encompasses the
NHPUC's order of March 20, 1998.
On May 11, 1998 the NHPUC issued an order requiring Connecticut Valley to
show cause why it should not be held in contempt for its failure to meet the
compliance filing requirements of its March 20, 1998 Order. A hearing on this
matter was scheduled for June 11, 1998, which was subsequently cancelled
because of the Federal Court's June 5, 1998 Order, discussed below.
On June 5, 1998, the Court issued an Order which denied the NHPUC's
motion for a stay of the Court's preliminary injunction. The Order clearly
states that no restructuring effort in New Hampshire can move forward without
the Court's approval unless all New Hampshire utilities agree to the plan.
The Order suspends all involuntary restructuring efforts for all New Hampshire
utilities until a hearing on the merits is conducted. The Company believes
that the Court will convert the preliminary injunction to a permanent
injunction after a hearing which is expected to occur during the first half of
1999. The NHPUC has appealed this Order to the Circuit Court of Appeals.
These appeals have been fully briefed, and the Court of Appeals conducted oral
argument on October 6, 1998.
As a result of these Court orders, Connecticut Valley's 1997 charges
under SFAS No. 5 and SFAS No. 71, described above, were reversed in the first
quarter of 1998. Combined, the reversal of these charges increased first
quarter 1998 net income and earnings per share of common stock by
approximately $4.5 million and $.39, respectively.
On April 1, 1998, Citizens Bank of New Hampshire (Bank) notified
Connecticut Valley that it was in default of the Loan Agreement between the
Bank and Connecticut Valley dated December 27, 1994 and that the Bank 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 has satisfied the Bank's requirements for curing the
violation.
On June 25, 1997, the Company filed with the FERC a notice of termination
of its power supply contract with Connecticut Valley, conditional upon the
Company's request to impose a surcharge on the Company's transmission tariff
to recover the stranded costs that would result from the termination of its
contract with Connecticut Valley. The amount requested was $44.9 million plus
interest at the prime rate to be recovered over a ten-year period. In its
Order dated December 18, 1997 in Docket No. ER97-3435-000, the FERC rejected
the Company's proposed stranded cost surcharge mechanism but indicated that it
would consider an exit fee mechanism for collecting stranded costs. The FERC
also rejected the Company's arguments concerning the applicability of stated
FERC policies regarding retail stranded costs, multi-state regulatory gaps and
the implications of state restructuring initiatives. The Company filed a
motion seeking rehearing of the FERC's December 18, 1997 Order which was
denied. In addition, and in accordance with the December 18, 1997 FERC Order,
on January 12, 1998 the Company filed a request with the FERC for an exit fee
mechanism to collect $44.9 million in a lump sum, or in installments with
interest at the prime rate over a ten-year period, to cover the stranded costs
resulting from the cancellation of Connecticut Valley's power contract with
the Company.
On March 11, 1998, the FERC issued an order accepting for filing the
Company's request for an exit fee effective March 14, 1998, and set hearings
to determine: whether Connecticut Valley will become an unbundled
transmission customer of the Company, the Company's expectation as to the
period of time it would serve Connecticut Valley, and the allowable amount of
the exit fee. The FERC also rejected the Company's June 25, 1997 notice of
termination indicating that the notice can be resubmitted when the power
contract is proposed to be terminated.
On April 28, 1998, the Company filed its case-in-chief before the FERC
updating the amount of the exit fee to $54.9 million in a lump sum, describing
all of the ways Connecticut Valley will become an unbundled transmission
customer of the Company subsequent to termination, and establishing the
expected period of service based upon the date of termination, whenever that
occurs, and the weighted average service life of its commitments to power
resources to serve Connecticut Valley. Had termination taken effect on
January 1, 1998 this expectation period would have equaled nineteen years.
On August 4 and 5, 1998 Phase 1 hearings were held at the FERC on the
issue of whether Connecticut Valley will become an unbundled tranmission
customer of the Company. Subsequent to those hearings, the parties agreed to
go on to hearings on the Phase 2 issues (addressing the allowable amount of
the exit fee) without a preliminary determination from the Administrative Law
Judge or the FERC on the Phase 1 issues. The Company will submit supplemental
testimony on Phase 2 issues in December 1998.
If the Company is unable to obtain an order authorizing the full recovery
amount of the exit fee, or other appropriate mechanism, the Company would be
required to recognize a loss under SFAS No. 5 totaling approximately
$75.0 million on a pre-tax basis. Furthermore, the Company would be required
to write-off approximately $4.0 million in regulatory assets associated with
its wholesale business under SFAS No. 71 on a pre-tax basis. Conversely, even
if the Company obtains a FERC order authorizing the updated requested exit
fee, Connecticut Valley would be required to recognize a loss under SFAS No. 5
of approximately $54.9 million on a pre-tax basis unless Connecticut Valley
has obtained an order by the NHPUC or other appropriate body directing the
recovery of those costs in Connecticut Valley's retail rates. Either of these
reasonably possible outcomes could occur during calendar year 1999.
The Company has initiated and will continue to work for a negotiated
settlement with parties to the New Hampshire restructuring proceeding and the
NHPUC. On September 14 and 15, 1998 the Company participated in a settlement
conference with an administrative law judge assigned for the settlement
process at the FERC and the parties to the Company's exit fee filing. The
Company cannot predict the ultimate outcome of this matter. However, an
adverse resolution would have a material adverse effect on the Company's
results of operations, cash flows, and ability to obtain capital at
competitive rates. Either of these reasonably possible outcomes could occur
during calendar year 1999.
Note 4 - Investment in Vermont Yankee Nuclear Power Corporation
The Company accounts for its investment in Vermont Yankee using the
equity method. Summarized financial information for Vermont Yankee Nuclear
Power Corporation follows:
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30 September 30
1998 1997 1998 1997
------- ------- -------- --------
<S> <C> <C> <C> <C>
Operating revenues $43,186 $41,967 $152,269 $126,771
Operating income $ 3,929 $ 3,526 $ 11,639 $ 10,816
Net income $ 1,816 $ 1,721 $ 5,324 $ 5,244
Company's equity in net income $594 $548 $1,643 $1,649
</TABLE>
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
September 30, 1998
Earnings Overview
The Company recorded a net loss of $.2 million, or a loss of $.06 per
share of common stock for the third quarter of 1998, compared to net income of
$2.1 million, or $.14 per share of common stock during the same period last
year. Due to the Company's winter sales peak and higher winter rates, the
Company normally experiences losses in the second and third quarters when
sales are lower and rates are reduced.
Lower third quarter 1998 earnings compared to the third quarter of 1997
resulted primarily from higher net power costs during the 1998 quarter and an
after tax gain of approximately $1.8 million or $.16 per share of common stock
from a non-recurring asset sale recorded in 1997.
For the nine months ended September 30, 1998, net income was
$4.6 million, or $.27 per share of common stock compared to $14.5 million, or
$1.13 per share of common stock for the 1997 period.
Included in net income and earnings per share of common stock in the
first nine months of 1998 is the positive impact of the reversal of a fourth
quarter 1997 charge of $3.6 million (after-tax) and $.31, respectively, and an
after-tax extraordinary credit of $.9 million and $.08, respectively, at the
Company's New Hampshire utility subsidiary, Connecticut Valley Electric
Company Inc. Net income and earnings per share of common stock for the first
nine months of 1997 reflect after-tax gains of $3.1 million and $.28,
respectively, from non-recurring asset sales.
Absent the 1998 reversal of the fourth quarter 1997 charge of
$3.6 million and the extraordinary credit of $.9 million, 1998's first nine
months net income would have been $.1 million, or a loss of $.12 per share of
common stock. Net income for the first nine months of 1997 absent
non-recurring asset sales was $11.4 million, or $.85 per share of common stock.
Other factors affecting results for 1998 are described in results of
operations below.
On June 12, 1998, the Company filed with the PSB a request for a 10.7%
rate increase ($24.7 million of annualized revenues) effective March 1, 1999.
On October 27, 1998, the Company reached an agreement with the DPS regarding
this rate increase request.
The agreement, if approved by the PSB, provides for a temporary rate
increase in the Company's Vermont retail rates of 4.7% or $10.9 million on an
annualized basis beginning with service rendered January 1, 1999. The
temporary rate increase is subject to adjustment upon future resolution of the
Hydro-Quebec Contract issues presently before the VSC discussed in Note 3,
Retail Rates above.
Operating Revenues and MWH Sales
A summary of MWH sales and operating revenues for the three and nine
months ended September 30, 1998 and 1997 (and the related percentage changes
from 1997) is set forth below:
<TABLE>
<CAPTION>
Three Months Ended September 30
------------------------------------------------
Percentage Percentage
MWH Increase Revenues (000's) Increase
1998 1997 (Decrease) 1998 1997 (Decrease)
------- ------- ---------- ------- ------- ----------
<S> <C> <C> <C> <C> <C> <C>
Residential 215,475 213,402 1.0 $24,894 $24,744 .6
Commercial 242,033 234,354 3.3 24,310 23,913 1.7
Industrial 99,229 99,945 (.7) 6,888 6,997 (1.6)
Other retail 1,799 1,816 (.9) 488 496 (1.6)
------- ------- ------- -------
Total retail sales 558,536 549,517 1.6 56,580 56,150 .8
------- ------- ------- -------
Resale sales:
Firm 492 258 90.7 24 11 118.2
Entitlement 93,320 91,983 1.5 4,562 4,458 2.3
Other 264,571 217,214 21.8 7,145 6,018 18.7
------- ------- ------- -------
Total resale sales 358,383 309,455 15.8 11,731 10,487 11.9
------- ------- ------- -------
Other revenues - - - 1,211 1,353 (10.5)
------- ------- ------- -------
Total sales 916,919 858,972 6.7 $69,522 $67,990 2.3
======= ======= ======= =======
Nine Months Ended September 30
---------------------------------------------------
Percentage Percentage
MWH Increase Revenues (000's) Increase
1998 1997 (Decrease) 1998 1997 (Decrease)
--------- --------- ---------- -------- -------- ----------
<S> <C> <C> <C> <C> <C> <C>
Residential 692,304 705,862 (1.9) $ 84,499 $ 85,032 (.6)
Commercial 694,801 680,489 2.1 74,953 76,451 (2.0)
Industrial 307,647 314,501 (2.2) 24,344 24,805 (1.9)
Other retail 5,364 5,365 - 1,457 1,455 .1
--------- --------- -------- --------
Total retail sales 1,700,116 1,706,217 (.4) 185,253 187,743 (1.3)
--------- --------- -------- --------
Resale sales:
Firm 1,617 755 114.2 61 34 79.4
Entitlement 229,076 287,469 (20.3) 14,825 14,025 5.7
Other 578,741 599,792 (3.5) 15,966 15,795 1.1
--------- --------- -------- --------
Total resale sales 809,434 888,016 (8.8) 30,852 29,854 3.3
--------- --------- -------- --------
Other revenues - - - 3,781 4,329 (12.7)
--------- --------- -------- --------
Total sales 2,509,550 2,594,233 (3.3) $219,886 $221,926 (.9)
========= ========= ======== ========
</TABLE>
Retail MWH sales for the third quarter of 1998 increased 1.6% compared to
the third quarter of 1997 resulting in an .8% increase in retail revenues.
For the nine months ended September 30, 1998, retail MWH sales were
relatively flat compared to the same period last year, decreasing only about
.4%. This minimal decrease resulted in a $2.5 million, or 1.3% decrease in
retail revenues. This negative variance is attributable to a $.6 million
impact of lower MWH sales in the first nine months of 1998 as compared to the
first nine months of 1997 and $1.9 million resulting from a modified rate
design reflected in bills rendered since April 1, 1997. The modified rate
design, which is revenue neutral on an annual basis, decreases prices charged
during the winter months of December through March and increases prices during
the remaining months of the year.
Entitlement MWH sales increased 1.5% or 1,337 MWH for the third quarter
compared to the same period in 1997. The increase results primarily from
increased sales to UNITIL and Hydro-Quebec under Schedule C1 Contract.
For the nine months ended September 30, 1998, entitlement MWH sales
decreased 20.3% and related revenues increased 5.7%, or $.8 million compared
to the same period last year. The decrease results primarily from the
scheduled refueling and maintenance outage of the Vermont Yankee plant, which
extended from March 21, 1998 through June 3, 1998, reducing MWH sales to
UNITIL. However, the higher costs of the Company's share of Vermont Yankee's
capacity costs associated with the refueling and maintenance outage are passed
on to entitlement customers resulting in an increase in entitlement revenues
of $.8 million, or 5.7%.
The increase in other resale sales and revenues for the third quarter of
1998 resulted primarily from increased short-term system capacity sales
partially offset by lower off-system sales.
The decrease in other resale sales for the nine months ended
September 30, 1998 resulted primarily from decreased off-system sales and
sales to Nepool partially offset by an increase in short-term system capacity
sales. However, due to market fluctuations, other resale revenues increased
$.2 million, or 1.1%.
The decrease on other revenues for the three and nine months ended
September 30, 1998 compared to the same periods last year results primarily
from lower revenues associated with a transmission interconnection agreement
and pole attachment rentals.
Net Purchased Power and Production Fuel Costs
The net cost components of purchased power and production fuel costs for
the three and nine months ended September 30, 1998 and 1997 are as follows
(dollars in thousands):
<TABLE>
<CAPTION>
Three Months Ended September 30
--------------------------------------------
1998 1997
Units Amount Units Amount
------- ------- ------- -------
<S> <C> <C> <C> <C>
Purchased and produced:
Capacity (MW) 543 $24,106 536 $23,703
Energy (MWH) 869,234 18,090 862,357 16,411
------- -------
Total purchased power costs 42,196 40,114
Production fuel (MWH) 96,602 612 42,799 518
------- -------
Total purchased power and
production fuel costs 42,808 40,632
Entitlement and other resale sales (MWH) 357,891 11,707 309,197 10,476
------- -------
Net purchased power and production
fuel costs $31,101 $30,156
======= =======
Nine Months Ended September 30
----------------------------------------------
1998 1997
Units Amount Units Amount
--------- ------- --------- -------
<S> <C> <C> <C> <C>
Purchased and produced:
Capacity (MW) 559 $71,221 571 $68,161
Energy (MWH) 2,408,734 56,563 2,567,333 53,254
------- -------
Total purchased power costs 127,784 121,415
Production fuel (MWH) 243,214 1,521 174,855 1,209
------- -------
Total purchased power and
production fuel costs 129,305 122,624
Entitlement and other resale sales (MWH) 807,817 30,791 887,261 29,820
------- -------
Net purchased power and production
fuel costs $98,514 $92,804
======= =======
</TABLE>
Net purchased power and production fuel costs increased $.9 million, or
3.1% for the third quarter of 1998 compared to the third quarter of 1997.
This variance is mostly attributable to increased purchases from small power
qualifying and higher costs under the Hydro-Quebec power contract.
For the nine months ended September 30, 1998, net purchased power and
production fuel costs increased $5.7 million, or 6.2% compared to the same
period last year. However, absent the benefit of the 1997 Connecticut Valley
reversal discussed above, net purchased power and production fuel costs
increased $11.2 million, or 12.1% for 1998 compared to the same period last
year primarily as the result of the Vermont Yankee extended outage, increased
purchases from small power qualifying and higher costs under the Hydro-Quebec
power contract.
Pursuant to a Vermont Public Service Board (PSB) Accounting Order, first
half 1997 energy costs were reduced by approximately $5.8 million related to a
Hydro-Quebec agreement.
The Company owns and operates 20 hydroelectric generating units and two
gas turbines and one diesel peaking unit with a combined capability of
73.7 MW. The Company has equity ownership interests in four nuclear
generating companies: Vermont Yankee, Maine Yankee, Connecticut Yankee and
Yankee Atomic. In addition, the Company maintains joint-ownership interests
in Joseph C. McNeil, a 53 MW wood, gas and oil-fired unit; Wyman #4, a 619 MW
oil-fired unit; and Millstone Unit #3, an 1154 MW nuclear unit.
MERRIMACK UNIT #2
Until its termination on April 30, 1998, the Company purchased power and
energy from Merrimack Unit #2 pursuant to a contract dated July 16, 1966
entered into by and between Vermont Electric Power Company (VELCO) and Public
Service Company of New Hampshire (PSNH). Pursuant to the contract, as
amended, VELCO agreed to reimburse PSNH, in the proportion which the VELCO
quota bears to the demonstrated net capability of the plant, for all fixed
costs of the unit and operating costs of the unit incurred by PSNH, which are
reasonable and cost-effective for the remaining term of the VELCO contract.
In early 1998, PSNH took the Merrimack Unit #2 facility off line, shut it down
and commenced a maintenance outage. In February, March and April of 1998,
PSNH billed VELCO for costs to complete the maintenance outage. VELCO
disputes the validity of a portion of the charges on grounds that the
maintenance performed at the unit was to extend the life of the Merrimack
plant beyond the term of the VELCO contract and that the charges in connection
with said investments were not reasonable and cost-effective for the remaining
term of the VELCO contract. The Company estimates that the portion of the
disputed charges allocable to the Company are approximately $1.0 million on a
pre-tax basis. Such amounts have not been paid or expended at this time.
NUCLEAR MATTERS
The Company maintains a 1.7303% joint-ownership interest in Millstone
Unit #3 of the Millstone Nuclear Power Station and owns a 2% equity interest
in Connecticut Yankee. These two plants are operated by Northeast Utilities
(NU). The Company also owns 2%, 3.5% and 31.3% equity interests in Maine
Yankee, Yankee Atomic and Vermont Yankee, respectively.
Millstone Unit #3
Millstone Unit #3 (Unit #3) received approval by the NRC commissioners
and NRC staff on June 15, 1998 and June 29, 1998, respectively, to restart
Unit #3 which was shut down on March 30, 1996, due to numerous technical and
non-technical problems. Unit #3 reached full power operation on July 14,
1998. The Company's share of the total incremental operating and maintenance
costs for Unit #3 were about $.9 million for 1997 and about $.3 million for
1998. Incremental replacement power costs for 1998 were about $1.9 million
for the six month period that Unit #3 was out of service.
The Company remains actively involved with the other non-operating
minority joint-owners of Unit #3. This group is engaged in various activities
to monitor and evaluate NU and Northeast Utilities Service Co.'s efforts
relating to Unit #3. On August 7, 1997, the Company and eight other
non-operating owners of Unit #3 filed a demand for arbitration with Connecticut
Light and Power Company and Western Massachusetts Electric Company and
lawsuits against NU and its trustees. The arbitration and lawsuits seek to
recover costs associated with replacement power, operation and maintenance
costs and other costs resulting from the shutdown of Unit #3. The
non-operating owners claim that NU and two of its wholly owned subsidiaries
failed
to comply with NRC's regulations, failed to operate the facility in accordance
with good operating practice and attempted to conceal their activities from
the non-operating owners and the NRC.
Maine Yankee
On August 6, 1997, the Maine Yankee's Nuclear Power plant was prematurely
retired from commercial operation. The Company relied on Maine Yankee for
less than 5% of its required system capacity.
Connecticut Yankee
On December 4, 1996, the Connecticut Yankee Nuclear power plant was
prematurely retired from commercial operation. The Company relied on
Connecticut Yankee for less than 3.0% of its required system capacity.
Yankee Atomic
In 1992, the Yankee Atomic Nuclear power plant was retired from
commercial operation. The Company relied on Yankee Atomic for less than 1.5%
of its system capacity.
Vermont Yankee
The Vermont Yankee Nuclear Power Plant, which provides approximately
one-third of the Company's power supply, began a refueling outage on
March 21,
1998 and returned to service on June 3, 1998. The refueling outage extended
twenty-six days beyond the scheduled forty-nine days. The Company incurred
approximately $3.1 million and $6.5 million for replacement energy and
maintenance costs, respectively, of which $7.2 million in total was deferred
consistent with current accounting and ratemaking practices. These deferrals
will be amortized to expense over eighteen months which is the expected
in-service period before Vermont Yankee's next scheduled refueling outage.
The Design Basis Documentation project (Project) initiated by Vermont
Yankee during 1996 is expected to be completed by the end of year 2000. The
Company's 35% share of the total cost for this Project is expected to be about
$6.2 million. Such costs will be deferred by Vermont Yankee and amortized
over the remaining license life of the plant.
Vermont Yankee has received expressions of interest to purchase Vermont
Yankee. Discussions between Vermont Yankee and these parties are continuing.
Presently, costs billed to the Company by Maine Yankee, Connecticut
Yankee and Yankee Atomic, including a provision for ultimate decommissioning
of the units, are being collected from the Company's customers through
existing retail and wholesale rate tariffs. The Company's share of remaining
costs with respect to Maine Yankee, Connecticut Yankee and Yankee Atomic's
decisions to discontinue operation is approximately $16.0 million,
$12.0 million and $3.9 million, respectively. These amounts are subject to
ongoing review and revisions and are reflected in the accompanying balance
sheet both as regulatory assets and nuclear decommissioning costs (current and
non-current). Although the estimated costs of decommissioning are subject to
change due to changing technologies and regulations, the Company expects that
the nuclear generating companies' liability for decommissioning, including any
future changes in the liability, will be recovered in their rates over their
operating or license lives.
The decision to prematurely retire these three nuclear power plants was
based on economic analyses of the costs of operating them compared to the
costs of closing them and incurring replacement power costs over the remaining
period of the plants' operating licenses. The Company believes that based on
the current regulatory process, its proportionate share of Maine Yankee,
Connecticut Yankee and Yankee Atomic decommissioning costs will be recovered
through the regulatory process and, therefore, the ultimate resolution of the
premature retirement of the three plants has not and will not have a material
adverse effect on the Company's earnings or financial condition.
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 Federal approval by five 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.
Other Operation
Other operating expenses increased $2.4 million for the nine months ended
September 30, 1998 principally due to an increase in distribution, consulting
services and regulatory commission expenses partially offset by an increase in
deferral of conservation and load management costs.
Maintenance
Maintenance expenses for the three months ended September 30, 1998
decreased $.4 million compared to the same period in 1997 primarily due to
Unit #3 being back on line.
The increase in maintenance expenses of $.5 million for the nine months
ended September 30, 1998 compared to the same period in 1997 is mostly
attributable to the severe ice storm in January 1998 partially offset by lower
maintenance costs related to Unit #3.
Income Taxes
Federal and state income taxes fluctuate with the level of pre-tax
earnings. The decrease in total income tax expense for the three and nine
months ended September 30, 1998 results primarily from a decrease in pre-tax
earnings for the periods.
Other Income and Deductions
The decrease in other income, net for the 1998 three and nine months
periods results from lower subsidiaries' earnings (see Diversification below)
and gains of $2.1 million and $2.9 million from non-recurring asset sales in
February and August 1997, respectively.
Extraordinary Credit
The extraordinary credit net of taxes of $.9 million represents a
reversal of a charge of a like amount taken in the fourth quarter of 1997
discussed above.
Dividends Declared
The decrease in common dividends declared results from an early
declaration made in December 1997 for the quarterly dividend paid on
February 13, 1998.
LIQUIDITY AND CAPITAL RESOURCES
The Company's liquidity is primarily affected by the level of cash
generated from operations and the funding requirements of its ongoing
construction and C&LM programs. Net cash flow provided by operating
activities was $16.0 million and $37.0 million for the nine months ended
September 30, 1998 and 1997, respectively. The reduction is due to reduced
cash earnings, the extended refueling outage at the Vermont Yankee Nuclear
Power Plant in the 1998 period, and higher tax payments.
The Company ended the first nine months of 1998 with cash and cash
equivalents of $10.2 million, a decrease of $6.4 million from the beginning of
the year. The decrease in cash for the first nine months of 1998 was the
result of $16.0 million provided by operating activities, offset by
$13.6 million used for investing activities and $8.8 million used for
financing activities.
Operating Activities - Net income, depreciation and deferred income taxes
and investment tax credits provided $19.6 million. About $3.6 million of cash
was used for working capital needs and other operating activities.
Investing Activities - Construction and plant expenditures consumed
approximately $11.6 million, while $2.0 million was used for C&LM programs and
non-utility investments.
Financing Activities - Dividends paid on common stock were $7.0 million
while preferred dividends were $1.5 million. Short-term obligations required
$.7 million and sale of Treasury Stock provided $.4 million.
The level of short-term borrowings fluctuates based on seasonal corporate
needs, the timing of long-term financings and market conditions.
The Company has a $50.0 million revolving credit facility with a group of
banks which matures on June 1, 1999. No borrowings were outstanding at
September 30, 1998 but borrowings are expected to be in the range of $10.0 to
$15.0 million by June 1, 1999 as a result of scheduled first mortgage bond
maturities. In addition, the Company must rollover an aggregate of
$16.3 million of letters of credit between May 1999 and December 1999. The
Company's ability to extend or replace the maturing $50.0 million revolving
credit facility and roll over $16.3 million of maturing letters of credit will
be dependent in large part on a positive outcome of the pending Hydro-Quebec
Contract issues at the VSC.
Connecticut Valley has outstanding long-term bank debt of $3.75 million
expiring December 27, 1999. Discussions continue between Connecticut Valley
and the Bank to extend this facility and to re-establish the $.8 million
committed line of credit which expired on May 31, 1998.
The Company's capital structure ratios as of September 30, 1998
(including amounts of long-term debt and preferred stock due within one year)
consisted of 51.8% common equity, 7.5% preferred stock and 40.7% long-term
debt including capital lease obligations.
Current credit ratings of the Company's securities as reaffirmed by Duff
& Phelps and Standard & Poor's are as follows:
Duff & Standard
Phelps & Poor's
------ --------
First Mortgage Bonds BBB A-
Corporate Credit Rating BBB
Preferred Stock BBB- BBB-
On January 22, 1998, Standard & Poor's revised its ratings outlook on the
Company to negative from stable stating that the revised outlook reflects the
adverse ruling by the NHPUC related to Connecticut Valley discussed above.
Catamount, a wholly owned non-utility subsidiary of the Company, has a
credit facility which provides for up to $8.0 million of letters of credit and
working capital loans. Currently, a $1.2 million letter of credit is
outstanding to support certain of Catamount's obligations in connection with a
debt reserve requirement in the Appomattox Cogeneration project.
Financial obligations of the non-utility wholly owned subsidiaries are
non-recourse to the Company.
Hydro-Quebec Contract
The Company is a party to a power contract with Hydro-Quebec through the
VJO, a consortium of Vermont utilities. Under the contract with Hydro-Quebec
and a separate Vermont Participants Agreement, there are step up provisions
that provide that in the event any VJO member fails to meet its obligation
under the contract with Hydro-Quebec, the balance of the VJO partipants,
including the Company, will "step up" to the defaulting party's share on a
pro-rata basis. As of September 30, 1998 the Company's VJO obligation is
approximately 47% of the total contract.
On November 6, 1998, in connection with a severe ice storm during January
1998, the VJO filed a Notice of Arbitration in which it sets forth grounds for
termination of the Hydro-Quebec contract that include, among others, several
material defaults on the part of Hydro-Quebec with respect to the
construction, maintenance and design of its transmission system. The contract
provides that the arbitration will be conducted in Burlington, Vermont and
under the auspices of the American Arbitration Association.
Diversification
Catamount was formed for the purpose of investing in non-regulated power
plant projects. Currently, Catamount, through its wholly owned subsidiaries,
has interests in six operating independent power projects located in Glenns
Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; Hopewell,
Virginia; and Thetford, England. In addition, Catamount has interests in a
project under construction in Fort Dunlop, England, and a project under
development in Summersville, West Virginia. Catamount's after-tax earnings
were $.8 million and $2.6 million for the third quarter of 1998 and 1997,
respectively, and $2.1 million and $3.6 million for the first nine months of
1998 and 1997, respectively.
SmartEnergy was formed to engage in the sale of or rental of electric
water heaters, energy efficient products and other related goods and services.
SmartEnergy incurred losses of $.4 million and $.2 million for the third
quarter of 1998 and 1997, respectively, and losses of $1.2 million and
$.2 million for the first nine months of 1998 and 1997, respectively. These
losses are associated with activities that are intended to position
SmartEnergy for possible entry into several niches of national retail markets.
SmartEnergy has signed an agreement to manufacture and deliver the SmartDrive
dairy vacuum pump control to domestic and worldwide markets beginning later
this year. Participants in this arrangement are Babson Brothers Company and
Asea Brown Boveri.
Rates and Regulation
The Company recognizes that adequate and timely rate relief is necessary
if the Company is to maintain its financial strength, particularly since
Vermont regulatory rules do not allow for changes in purchased power and fuel
costs to be passed on to consumers through automatic rate adjustment clauses.
The Company's practice of reviewing costs periodically will continue and rate
increases will be requested when warranted.
Vermont: On September 22, 1997, the Company filed for a 6.6% or
$15.4 million general rate increase to become effective June 6, 1998 to offset
increasing cost of providing service. Approximately $14.3 million or 92.9% of
the rate increase request is to recover contractual increases in the cost of
power the Company purchases from Hydro-Quebec.
At the same time, the Company also filed a request to eliminate the
winter-summer rate differential and price electricity the same year-round.
The change would be revenue-neutral within classes of customers and overall.
Over time, customers would see a leveling off of rates so they would pay the
same per kilowatt-hour during the winter and summer months.
On June 12, 1998, the Company filed with the PSB for a 10.7% retail rate
increase to be effective March 1, 1999. This rate case proceeding overlaps
the 6.6% rate increase request referenced above that is now stayed pending a
review on the so-called preclusion issue by the Vermont Supreme Court. On
October 27, 1998, the Company reached an agreement with the DPS regarding the
10.7% rate increase request.
The agreement, if approved by the PSB, provides for a temporary rate
increase in the Company's Vermont retail rates of 4.7% or $10.9 million on an
annualized basis beginning with service rendered January 1, 1999. The
temporary rate increase is subject to adjustment upon future resolution of the
Hydro-Quebec Contract issues presently before the VSC.
In addition, the agreement incorporates a pro forma disallowance of
approximately $7.4 million for the Company's purchased power costs under the
Hydro-Quebec Contract while the VSC reviews the PSB denial of the Company's
claim that the PSB is precluded from again trying the Company on certain
Hydro-Quebec Contract issues. The Company anticipates the PSB's decision on
the agreement during the fourth quarter of 1998 and a resolution of the
Hydro-Quebec contracts issues by the end of 1999.
If the Company receives an unfavorable ruling from the VSC, and the
methodology used to determine the temporary Hydro-Quebec disallowance is
continued for the duration of the Hydro-Quebec Contract, approximately
$205.0 million of power costs to be incurred under that contract would not be
recoverable in rates. This result would jeapordize the ability of the Company
to continue as a going concern.
New Hampshire: On November 26, 1997, Connecticut Valley filed a request
with the NHPUC to increase the FAC, PPCA and short-term energy purchase rates
effective on or after January 1, 1998. The requested increase in rates
results from higher forecast energy and capacity charges on power Connecticut
Valley purchases from the Company plus removal of credit effective during 1997
to refund overcollections from 1996.
In an order dated December 31, 1997, the NHPUC directed Connecticut
Valley to freeze its current FAC and PPCA rates (other than short-term rates
to be paid to certain Qualifying Facilities) effective January 1, 1998, on a
temporary basis pending a hearing to determine: 1) the appropriate proxy for a
market price that Connecticut Valley could have obtained if it had terminated
its wholesale contract with the Company; 2) the implications of allowing
Connecticut Valley to pass on to its customers only that market price; and
3) whether the NHPUC's final determination on the FAC and PPCA rates should be
reconciled back to January 1, 1998 or some other date.
For additional information on Vermont and New Hampshire rate and
regulatory matters see Electric Industry Restructuring discussed above and
Note 3 to the Consolidated Financial Statements.
Management Audit
On April 17, 1997, the PSB ordered an independent forward-looking
analysis of three of the Company's management policies and practices focusing
on three areas: 1) Transmission of information to the Company's Board of
Directors by management. 2) Cost-benefit analyses for major corporate
decisions. 3) Implementation of the Company's ethics and conflict of interest
policy. The PSB's consultant began work on the project during the first
quarter of 1998 and issued a final report during October 1998. The PSB has
not yet indicated any response to the report.
Proposed Formation of Holding Company
In order to further prepare Central Vermont Public Service Corporation
for deregulation, on July 24, 1998, the Company filed a petition with the PSB
for permission to create a holding company that would have as subsidiaries the
Company and non-utility subsidiaries-Catamount and SmartEnergy. The Company
believes that a holding company structure will facilitate the Company's
transition to a deregulated electricity market. The proposed holding company
formation must also be approved by Federal regulators, including the
Securities and Exchange Commission and the FERC, and by the holders of the
Company's shareholders.
New Accounting Pronouncement
In April 1998, the American Institute of Certified Public Accountants
issued Statement of Position 98-5, "Reporting on the Costs of Start-up
Activities" (SOP 98-5). SOP 98-5 provides guidance on the financial reporting
of start-up costs and organization costs. It requires costs of start-up
activities and organization costs to be expensed as incurred and is effective
for financial statements for fiscal years beginning after December 15, 1998.
The Company continues to evaluate the impact that the adoption of SOP 98-5
will have on the Company's financial position or results of operations.
Year 2000 Information Systems Modifications
The Company's information systems could be affected by the date change in
Year 2000 because most software application and operational programs will not
properly recognize calendar dates beginning in the Year 2000. If not
corrected, many computer applications could fail or create erroneous results.
In order to meet current and future business needs the Company retained
outside consultants to make its customer service applications Year 2000
compliant. In addition, the Company utilized both internal and external
resources to make other applications, including its desk top applications Year
2000 ready. Inventory and assessment activities are 100% complete. Overall
remediation efforts are estimated at approximately 50% complete. The Company
expects to achieve compliance with Year 2000 requirements for all of its
financial and operating systems during the second quarter of 1999.
The Company's operations would be adversely affected if a date-related
system failure occurred with one of its major power suppliers, such as
Hydro-Quebec or Vermont Yankee, or VELCO, the company responsible for
transmission
in Vermont. VELCO indicates it will be compliant by September 1999. Other
delivery systems outside the state could, in the event of a date-related
system failure, cause additional power supply interruptions. The Company has
requested written reports from its power supply vendors regarding each
company's status relative to Year 2000 compliance and based on responses to
date, these power supply vendors have indicated that they are either currently
compliant or expect to be compliant by June 1999.
The Company has also requested compliance information from other major
vendors and suppliers. While this process is not yet complete, based upon
responses to date, many of those major vendors and suppliers have indicated
that they will be Year 2000 compliant in a timely manner. However, there can
be no guarantee that third parties' noncompliance and their failure to
remediate Year 2000 issues would not have a material adverse effect on the
Company.
Failure on the part of the Company to comply by December 31, 1999 would
have a material adverse effect on the Company's results of operations,
liquidity and financial condition. Also, failures of the Company's principal
power and transmission suppliers to remedy Year 2000 compliance issues, could
have a material adverse effect on the Company should non-compliance result
interruptions of power supply and transmission.
The Company is part of the Northeast grid contingency plan that would go
into effect immediately which will provide electricity to its customers on a
priority basis in the event of power outages. The Company also has
contingency plans developed in the event of the failure of its transmission,
generation, distribution, metering, telecommunications, information and
public communications systems. In addition, the State of Vermont has developed
a contingency plan that deals with electrical emergencies.
The Company believes it will incur approximately $2.8 million of costs
associated with making the necessary modifications to its centralized and
non-centralized computer systems. As of September 30, 1998, approximately
$1.7 million of those costs have been incurred.
During the first quarter of 1998, the Company requested an Accounting
Order from the PSB to defer these operating and maintenance costs. On
August 31, 1998, the PSB issued an Accounting Order authorizing the Company to
defer these costs and amortize them over a five-year period beginning
January 1, 2000.
The Company believes that these costs will be recovered through the
regulatory process and do not represent the potential for a material adverse
effect on its financial position or results of operations.
ELECTRIC INDUSTRY RESTRUCTURING
The electric utility industry is in a period of transition that may
result in a shift away from ratemaking based on cost of service and return on
equity to more market-based rates. Many states, including Vermont and
New Hampshire, where the Company does business, are exploring new mechanisms
to bring greater competition, customer choice and market influence to the
industry while retaining the public benefits associated with the current
regulatory system.
Vermont
On December 31, 1996, the PSB issued a Report and Order (the Report)
outlining a restructuring plan (the Plan), subject to legislative approval,
for the Vermont electric utility industry.
Due to uncertainty surrounding legislative schedules, the PSB, on
April 18, 1997, issued an Order which suspended, pending further legislative
action or future PSB Orders, certain filing deadlines for reports and plans to
be completed in connection with the Plan.
On April 3, 1997, Senate bill 62 (S.62), an act relating to electric
industry restructuring was passed by the Vermont Senate. Pursuant to S.62,
electric utility customers would have been entitled to purchase electricity in
a competitive market place and could have chosen their electricity supplier.
Incumbent investor-owned electric utilities, including the Company, would have
been required to separate their regulated distribution and transmission
operations into affiliate entities that were functionally separate from
competitive generation and retail operations. S.62 provided for the recovery
of a portion of investor-owned utility's "above market costs" which became
stranded on account of the introduction of competition within their service
area. When considering the recovery of such amounts, S.62 would have required
the PSB to weigh the goal of sharing net prudently incurred, discretionary
above-market costs "evenly" between utilities and customers against other
goals including preserving the continuing financial integrity of the existing
utility and respecting the just interests of investors. The Company believes
that the unmodified provisions of S.62 would not have met the criteria for
continuing application of SFAS No. 71. S.62 also created an incentive for the
Company to take steps to close the Vermont Yankee Nuclear Power Station by
conditioning the recovery of certain plant-related stranded costs on the
decision of its owners to cease operations in 1998, unless the PSB agreed to
allow the plant to run for up to two more refuelings to avoid power shortages
or for other public interest reasons. To become law, S.62 would have had to
be passed by the Vermont House of Representatives and signed by the Governor
of the State of Vermont. Since the 1998 Legislative session concluded in
April 1998 and S.62 was not enacted by the Vermont House, the bill did not
become effective and any efforts to pursue it in the future will require that
it be re-enacted by the Vermont Senate and passed by the House.
Instead of considering S.62, the Vermont House of Representatives
convened a special committee to study matters relating to the reform of
Vermont's electric utility system in the summer of 1997. That committee
issued recommendations in a report and legislation was proposed that would
have provided for reform but not adopt the recommendations concerning customer
choice and competition set forth in the PSB's Report and Order. Other
legislation intended to advance a portion of the PSB Report and Order was also
introduced. However, neither the House nor Senate acted on these reforms
which must be reintroduced in the next legislative biennium beginning in
January 1999, if they are to be considered. Therefore, at this time, it
cannot be determined whether future restructuring legislation will be enacted
in 1999 that would conform to the concepts developed by the Report, S.62 or
the House Special Committee report.
On July 22, 1998, Governor Dean issued an Executive Order establishing a
Working Group On Vermont' Electricity Future to lead a new effort to review
the issues of potential restructuring of Vermont's electric industry. Members
of the Working Group include individuals with both business and governmental
experience including a former chairman of the PSB. The purpose of the Working
Group is to determine the best structure for the electric industry in Vermont
so as to achieve the lowest current and long-term electric costs for all
classes of electric consumers. While any recommendations developed through
this effort cannot be implemented without regulatory and/or legislative
enactments, the Governor has expressed that he hopes that the creation of the
Working Group will provide an independent, non-partisan, fact-based analysis
and examination of the issues surrounding electric restructuring and help pave
the way to some type of proposal to pass the 1999 Vermont General Assembly.
The Working Group is charged with presenting a report, with recommendations,
to the Governor and Legislative leaders by December 15, 1998. In the months
since its establishment, the Working Group has convened a series of meetings
and engaged in fact finding with interested parties, including Vermont
utilities. At this time, the task force has yet to issue a preliminary report
of its recommendations.
On August 27, 1998, the PSB hosted a workshop entitled, "Electricity
Futures: Reforming Vermont's Power Supply", which was organized to facilitate
power supply reform. Participants heard reports on successful power supply
reforms in other states, followed by a discussion intended to identify
opportunities and next steps, and to elicit proposals for reformulating
Vermont's electric power supply. This workshop generated a great deal of
interest with over 140 attendees, representing Vermont retail electric
utilities, both large and small electricity consumers, public officials and
interest groups, and several current and aspiring energy suppliers. As a
follow up to the workshop, on September 15, 1998, the PSB opened a formal
proceeding in Docket No. 6140 with the goal of creating a regulatory
environment and a procedural framework to call forth, for disciplined review,
proposals for reducing current and future power costs in Vermont. The PSB
explained that it intends that this proceeding will define one or more
acceptable courses for reform, and will create the framework to enable Vermont
utilities and other interested parties to pursue them and to present them for
regulatory approval in an open, public process. All Vermont utilities were
made a party to that proceeding. Subsequent to the PSB's announcement,
preliminary position paper were filed and a technical conference was convened
with the PSB to recommend the scope of the investigation and potential courses
for reform of Vermont's power supply. As of this time, the PSB has yet to act
on any of the proposal or recommendations made concerning the disposition of
the matters in Docket No. 6140.
In order to further prepare Central Vermont Public Service Corporation
for deregulation, on July 24, 1998, the Company filed a petition with the PSB
for permission to create a holding company that would have as subsidiaries the
Company and non-utility subsidiaries-Catamount and SmartEnergy. The Company
believes that a holding company structure will facilitate the Company's
transition to a deregulated electricity market. The proposed holding company
formation must also be approved by Federal regulators, including the
Securities and Exchange Commission and the FERC, and by the Company's
shareholders.
New Hampshire
On February 28, 1997 the NHPUC published its detailed Final Plan to
restructure the electric utility industry in New Hampshire. Also on
February 28, 1997, the NHPUC, in a supplemental order specific to Connecticut
Valley, found that Connecticut Valley was imprudent for not terminating the
FERC-authorized power contract between Connecticut Valley and the Company,
required Connecticut Valley to give notice to cancel its contract with the
Company and denied stranded cost recovery related to this power contract.
Connecticut Valley filed for rehearing of the February 28, 1997 NHPUC Order.
On April 7, 1997, the NHPUC issued an Order addressing certain threshold
procedural matters raised in motions for rehearing and/or clarification filed
by various parties, including Connecticut Valley, relative to the Final Plan
and interim stranded cost orders. The April 7, 1997 Order stayed those
aspects of the Final Plan that were the subject of rehearing or clarification
requests and also stayed the interim stranded cost orders for the various
parties, including Connecticut Valley. As such, those matters pertaining to
the power contract between Connecticut Valley and the Company were stayed.
The suspension of these orders was to remain in effect until two weeks
following the issuance of any order concerning outstanding requests for
rehearing and clarification.
On March 20, 1998, the NHPUC issued an order which affirmed, clarified
and modified various generic policy statements including the reaffirmation to
establish rates on the basis of a regional average announced previously in its
February 28, 1997 Final Plan. The March 20, 1998 order also addressed all
outstanding motions for rehearings or clarification relative to the policies
or legal positions articulated in the Final Plan and removed the stay covering
the Company's interim stranded cost order of April 7, 1997. In addition, the
March 20, 1998 Order imposed various compliance filing requirements.
On November 17, 1997, the City of Claremont, New Hampshire (Claremont),
filed with the NHPUC a petition for a reduction in Connecticut Valley's
electric rates. Claremont based its request on the NHPUC's earlier finding
that Connecticut Valley's failure to terminate its wholesale power contract
with the Company as ordered in the NHPUC Stranded Cost Order of February 28,
1997 was imprudent. Under the wholesale power purchase contract with the
Company, Connecticut Valley may terminate service at the end of a service
year, provided it has given written notice of termination prior to the
beginning of that service year. Claremont alleges that if Connecticut Valley
had given written notice of termination to the Company in 1996 when
legislation to restructure the electric industry was enacted in New Hampshire,
Connecticut Valley's obligation to purchase power from the Company would have
terminated as of January 1, 1998.
On November 26, 1997, Connecticut Valley filed a request with the NHPUC
to increase the FAC, PPCA and short-term energy purchase rates effective on or
after January 1, 1998. The requested increase in rates resulted from higher
forecast energy and capacity charges on power Connecticut Valley purchases
from the Company plus removal of a credit effective during 1997 to refund
overcollections from 1996. Connecticut Valley objected to the NHPUC's notice
of intent to consolidate Claremont's petition into the FAC and PPCA docket,
stating that Claremont's complaint should be heard as part of the NHPUC
restructuring docket. Over Connecticut Valley's objection at the hearing on
December 17, 1997, the NHPUC consolidated Claremont's petition with
Connecticut Valley's FAC and PPCA proceeding.
In an Order dated December 31, 1997 in Connecticut Valley's FAC and PPCA
docket, the NHPUC found Connecticut Valley acted imprudently by not
terminating the wholesale contract between Connecticut Valley and the Company,
notwithstanding the stays of its February 28, 1997 Orders. The NHPUC Order
further directed Connecticut Valley to freeze its current FAC and PPCA rates
(other than short term rates to be paid to certain Qualifying Facilities)
effective January 1, 1998, on a temporary basis, pending a hearing to
determine: 1) the appropriate proxy for a market price that Connecticut Valley
could have obtained if it had terminated its wholesale contract with the
Company; 2) the implications of allowing Connecticut Valley to pass on to its
customers only that market price; and 3) whether the NHPUC's final
determination on the FAC and PPCA rates should be reconciled back to
January 1, 1998 or some other date.
On January 19, 1998, Connecticut Valley and the Company filed with the
Federal District Court for a temporary restraining order to maintain the
status quo ante by staying the December 31, 1997 NHPUC Order and preventing
the NHPUC from taking any action that (i) compromises cost-based rate making
for Connecticut Valley or otherwise seeks to impose market price-based rate
making on Connecticut Valley; (ii) interferes with the FERC's exclusive
jurisdiction over the Company's pending application to recover wholesale
stranded costs upon termination of its wholesale power contract with
Connecticut Valley; or (iii) prevents Connecticut Valley from recovering
through retail rates the stranded costs and purchased power costs that it
incurs pursuant to its FERC-authorized wholesale rate schedule with the
Company.
On February 23, 1998, the NHPUC announced in a public meeting that it
reaffirmed its finding of imprudence and designated a proxy market price for
power at 4 cents per kWh in lieu of the actual costs incurred pursuant to the
wholesale power contract with the Company. In addition, the NHPUC indicated,
subject to certain conditions which were unacceptable to the companies, that
it would permit Connecticut Valley to maintain its current rates pending a
decision in Connecticut Valley's appeal of the NHPUC Order to the New
Hampshire Supreme Court.
Based on the December 31, 1997 NHPUC Order as well as the NHPUC's
February 23, 1998 announcement, which resulted in the establishment of
Connecticut Valley's rates on a non cost-of-service basis, Connecticut Valley
no longer qualified, as of December 31, 1997, for the application of SFAS
No. 71. As a result, Connecticut Valley wrote-off all of its regulatory
assets associated with its New Hampshire retail business for the year ended
December 31, 1997. This write-off amounted to approximately $1.2 million on a
pre-tax basis. In addition, Connecticut Valley recorded a $5.5 million
pre-tax loss as of December 31, 1997 under SFAS No. 5, "Accounting for
Contingencies," representing Connecticut Valley's estimated loss on power
contracts for the twelve months following December 31, 1997.
On April 3, 1998, the Court held a hearing on the Companies' motion for a
Temporary Restraining Order (TRO) and Preliminary Injunction against the NHPUC
at which time both the Companies and the NHPUC presented arguments. In an
oral ruling from the bench, and in a written order issued on April 9, 1998,
the Court concluded that the Companies had established each of the
prerequisites for preliminary injunctive relief and directed and required the
NHPUC to allow Connecticut Valley to recover through retail rates all costs
for wholesale power requirements service that Connecticut Valley purchases
from the Company pursuant to its FERC-authorized wholesale rate schedule
effective January 1, 1998 until further court order. In compliance with that
order, Connecticut Valley has received an order from the NHPUC authorizing
retail rates to recover such costs beginning in May 1998. On April 14, 1998,
the NHPUC filed a notice of appeal and a motion for a stay of the Court's
preliminary injunction. The NHPUC's request for a stay was denied.
Also, on April 3, 1998, the Court indicated that its earlier TRO
enjoining the NHPUC's restructuring orders applied to Connecticut Valley and
prohibits the enforcement of the restructuring orders until the Court conducts
a consolidated hearing and rules on the requests for permanent injunctive
relief by plaintiff PSNH and the other utilities that have been allowed to
intervene in these proceedings, including the Company and Connecticut Valley.
The plaintiffs-intervenors filed a motion asking the Court to extend its stay
of action by the NHPUC to implement restructuring and to make clear that the
stay encompasses the NHPUC's order of March 20, 1998.
On May 11, 1998 the NHPUC issued an order requiring Connecticut Valley to
show cause why it should not be held in contempt for its failure to meet the
compliance filing requirements of its March 20, 1998 Order. A hearing on this
matter was scheduled for June 11, 1998, which was subsequently cancelled
because of the Federal Court's June 5, 1998 Order, discussed below.
On June 5, 1998, the Court issued an Order which denied NHPUC's motion for
a stay of the Court's preliminary injunction. The Order clearly states that
no restructuring effort in New Hampshire can move forward without the Court's
approval unless all New Hampshire utilities agree to the plan. The Order
suspends all involuntary restructuring efforts for all New Hampshire utilities
until a hearing is conducted. The Company believes that the Court will
convert the preliminary injunction to a permanent injunction. The NHPUC has
appealed this Order to the Circuit Court of Appeals. These Appeals have been
fully briefed, and the Court of Appeals conducted oral argument on October 6,
1998.
As a result of these Court orders, Connecticut Valley's 1997 charges
under SFAS No. 5 and SFAS No. 71 described above were reversed in the first
quarter of 1998. Combined, the reversal of these charges increased first
quarter 1998 net income and earnings per share of common stock by
approximately $4.5 million and $.39, respectively.
On April 1, 1998, Citizens Bank of New Hampshire (Bank) notified
Connecticut Valley that it was in default of the Loan Agreement between the
Bank and Connecticut Valley dated December 27, 1994 and that the Bank 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 has satisfied the Bank's requirements for curing the
violation.
On June 25, 1997, the Company filed with the FERC a notice of termination
of its power supply contract with Connecticut Valley, conditional upon the
Company's request to impose a surcharge on the Company's transmission tariff
to recover the stranded costs that would result from the termination of its
contract with Connecticut Valley. The amount requested was $44.9 million plus
interest at the prime rate to be recovered over a ten-year period. In its
Order dated December 18, 1997 in Docket No. ER97-3435-000, the FERC rejected
the Company's proposed stranded cost surcharge mechanism but indicated that it
would consider an exit fee mechanism for collecting stranded costs. The FERC
also rejected the Company's arguments concerning the applicability of stated
FERC policies regarding retail stranded costs, multi-state regulatory gaps and
the implications of state restructuring initiatives. The Company has filed a
motion seeking rehearing of the FERC's December 18, 1997 Order. In addition,
and in accordance with the December 18, 1997 FERC Order, on January 12, 1998
the Company filed a request with the FERC for an exit fee mechanism to collect
$44.9 million in a lump sum, or in installments with interest at the prime
rate over a ten-year period, to cover the stranded costs resulting from the
cancellation of Connecticut Valley's power contract with the Company.
On March 11, 1998, the FERC issued an order accepting for filing the
Company's request for an exit fee effective March 14, 1998, and set hearings
to determine: whether Connecticut Valley will become an unbundled
transmission customer of the Company, the Company's expectation as to the
period of time it would serve Connecticut Valley, and the allowable amount of
the exit fee. The FERC also rejected the Company's June 25, 1997 notice of
termination indicating that the notice can be resubmitted when the power
contract is proposed to be terminated.
On April 28, 1998, the Company filed its case-in-chief before the FERC
updating the amount of the exit fee to $54.9 million in a lump sum, describing
all of the ways Connecticut Valley will become an unbundled transmission
customer of the Company subsequent to termination, and establishing the
expected period of service based upon the date of termination, whenever that
occurs, and the weighted average service life of its commitments to power
resources to serve Connecticut Valley. Had termination taken effect on
January 1, 1998 this expectation period would have equaled nineteen years.
On August 4 and 5, 1998 Phase 1 hearings were held at the FERC on the
issue of whether Connecticut Valley will become an unbundled tranmission
customer of the Company. Subsequent to those hearings, the parties agreed to
go on to hearings on the Phase 2 issues (addressing the allowable amount of
the exit fee) without a preliminary determination from the Administrative Law
Judge or the FERC on the Phase 1 issues. The Company will submit supplemental
testimony on Phase 2 issues on December 3, 1998.
If the Company is unable to obtain an order authorizing the full recovery
amount of the exit fee, or other appropriate mechanism, the Company would be
required to recognize a loss under SFAS No. 5 totaling approximately $75.0
million on a pre-tax basis. Furthermore, the Company would be required to
write-off approximately $4.0 million in regulatory assets associated with its
wholesale business under SFAS No. 71 on a pre-tax basis. Conversely, even if
the Company obtains a FERC order authorizing the updated requested exit fee,
Connecticut Valley would be required to recognize a loss under SFAS No. 5 of
approximately $54.9 million on a pre-tax basis unless Connecticut Valley has
obtained an order by the NHPUC or other appropriate body directing the
recovery of those costs in Connecticut Valley's retail rates. Either of these
reasonably possible outcomes could occur during calendar year 1998.
For further information on New Hampshire restructuring issues and other
regulatory events in New Hampshire affecting the Company or Connecticut Valley
and the December 1997 charges and reversals of the charges, see the Company's
Form 8-K dated January 12, 1998, January 28, 1998 and April 1, 1998; and Item
1. Business-New Hampshire Retail Rates, Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations-Electric Industry
Restructuring-New Hampshire and Item 8. Financial Statements and Supplementary
Data-Note 13, Retail Rates-New Hampshire in the Company's 1997 Form 10-K.
The Company has initiated and will continue to work for a negotiated
settlement with parties to the New Hampshire restructuring proceeding and the
NHPUC. 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. The
Company cannot predict the ultimate outcome of this matter. However, an
adverse resolution would have a material adverse effect on the Company's
results of operations, cash flows, and ability to obtain capital at
competitive rates.
Connecticut Valley constitutes approximately 7% of the Company's total
retail MWH sales.
Competition-Risk Factors
If retail competition is implemented in Vermont or New Hampshire, the
Company is unable to predict the impact of this competition on its revenues,
the Company's ability to retain existing customers and attract new customers
or the margins that will be realized on retail sales of electricity.
Historically, electric utility rates have been based on a utility's
costs. As a result, electric utilities are subject to certain accounting
standards that are not applicable to other business enterprises in general.
SFAS No. 71 requires regulated entities, in appropriate circumstances, to
establish regulatory assets and liabilities, and thereby defer the income
statement impact of certain costs and revenues that are expected to be
realized in future rates.
As described in Note 1 of Notes to Consolidated Financial Statements,
included in this Quarterly Report on Form 10-Q, the Company believes it
currently complies with the provisions of SFAS No. 71 for its regulated retail
and FERC regulated wholesale businesses. In the event the Company determines
that it no longer meets the criteria for following SFAS No. 71, the accounting
impact would be an extraordinary, non-cash charge to operations of
approximately $70.0 million on a pre-tax basis as of September 30, 1998.
Criteria that give rise to the discontinuance of SFAS No. 71 include
(1) increasing competition that restricts the Company's ability to establish
prices to recover specific costs and (2) a significant change in the manner in
which rates are set by regulators from cost-based regulation to another form
of regulation.
The Securities and Exchange Commission has questioned the ability of
certain utility companies continuing the application of SFAS No. 71 where
legislation provides for the transition to retail competition. Deregulation
of the price of electricity issues related to the application of SFAS No. 71
and 101, as to when and how to discontinue the application of SFAS No. 71 by
utilities during transition to competition has been referred to the Financial
Accounting Standards Board's Emerging Issues Task Force (EITF).
The EITF has reached a tentative consensus, and no further discussion is
planned, that regulatory assets should be assigned to separable portions of
the Company's business based on the source of the cash flows that will recover
those regulatory assets. Therefore, if the source of the cash flows is from a
separable portion of the Company's business that meets the criteria to apply
SFAS No. 71, those regulatory assets should not be written off under SFAS
No. 101, "Accounting for the Discontinuation of Application of SFAS No. 71,"
but should be assessed under paragraph 9 of SFAS No. 71 for realizability.
SFAS No. 121, "Accounting for the Impairment of Long Lived Assets and for
Long-Lived Assets to Be Disposed Of," which was adopted by the Company on
January 1, 1996, requires that any assets, including regulatory assets, that
are no longer probable of recovery through future revenues, be revalued based
upon future cash flows. SFAS No. 121 requires that a rate-regulated
enterprise recognize an impairment loss for the amount of costs excluded from
recovery. As of September 30, 1998, based upon the regulatory environment
within which the Company currently operates, SFAS No. 121 did not have an
impact on the Company's financial position or results of operations.
Competitive influences or regulatory developments may impact this status in
the future.
Because the Company is unable to predict what form possible future
restructuring legislation will take, it cannot predict if or to what extent
SFAS Nos. 71 and 121 will continue to be applicable in the future. In
addition, if the Company is unable to mitigate or otherwise recover stranded
costs that could arise from any potentially adverse legislation or regulation,
the Company would have to assess the likelihood and magnitude of losses
incurred under SFAS No. 5.
As such, the Company cannot predict whether any restructuring legislation
enacted in Vermont or New Hampshire, once implemented, would have a material
adverse effect on the Company's operations, financial condition or credit
ratings. However, the Company's failure to recover a significant portion of
its purchased power costs, would likely have a material adverse effect on the
Company's results of operations, cash flows and ability to obtain capital at
competitive rates. It is possible that stranded cost exposure associated with
SFAS Nos. 5, 71, and 121, before mitigation could exceed the Company's current
total common stock equity.
Forward Looking Statements
This document contains statements that are forward looking. These
statements are based on current expectations that are subject to risks and
uncertainties. Actual results will depend, among other things, upon general
economic and business conditions, weather, the actions of regulators,
including the outcome of the litigation involving Connecticut Valley before
the FERC and the Court and the Company's two pending rate cases before the PSB
and associated appeal to the Vermont Supreme Court, as well as other factors
which are described in further detail in the Company's filings with the
Securities and Exchange Commission. The Company cannot predict the outcome of
any of these proceedings or other factors.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
On July 29, 1996, the Company filed a Declaratory Judgment action in
the United States District Court for the District of Vermont. The Complaint
named as defendants a number of insurance companies that issued policies to
the Company dating from the mid 1940s to the late 1980s. The Company asserted
that policies issued by defendants provide coverage for all defense and
remediation costs associated with the Cleveland Avenue property, the
Bennington Landfill site and the North Clarendon site. Settlement has been
reached with all defendants. See Note 2 to the Consolidated Financial
Statements for related disclosures.
On August 7, 1997, the Company and eight other non-operating owners
of Unit #3 filed a demand for arbitration with Connecticut Light and Power
Company and Western Massachusetts Electric Company and lawsuits against NU and
its trustees. The arbitration and lawsuits seek to recover costs associated
with replacement power, operation and maintenance costs and other costs
resulting from the shutdown of Unit #3. The non-operating owners claim that
NU and two of its wholly owned subsidiaries failed to comply with NRC's
regulations, failed to operate the facility in accordance with good operating
practice and attempted to conceal their activities from the non-operating
owners and the NRC.
Except as otherwise described under Management's Discussion and
Analysis of Financial Condition and Results of Operations, Item 2, there are
no other material pending legal proceedings, other than ordinary routine
litigation incidental to the business, to which the Company or any of its
subsidiaries is a party or to which any of their property is subject.
Items 2, 3 and 4.
None.
Item 5. Other Information.
Effective November 2, 1998, Janice L. Scites was elected to
the Company's Board of Directors to replace Delano E. Lewis.
Item 6. Exhibits and Reports on Form 8-K.
(a) List of Exhibits
27. Financial Data Schedule.
(b) Item 5. There were no reports on Form 8-K for the quarter
ended September 30, 1998.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
(Registrant)
By Francis J. Boyle
Francis J. Boyle, Senior Vice President, Principal
Financial Officer and Treasurer
By James M. Pennington
James M. Pennington, Vice President, Controller
and Principal Accounting Officer
Dated November 13, 1998
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This Financial Data Schedule contains summary financial information extracted
from the Consolidated Financial Statements included herein and is qualified in
its entirety by reference to such financial statements (dollars in thousands,
except per share amounts).
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 319,215
<OTHER-PROPERTY-AND-INVEST> 65,145
<TOTAL-CURRENT-ASSETS> 57,756
<TOTAL-DEFERRED-CHARGES> 75,065
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 517,181
<COMMON> 66,438
<CAPITAL-SURPLUS-PAID-IN> 45,312
<RETAINED-EARNINGS> 73,883
<TOTAL-COMMON-STOCKHOLDERS-EQ> 185,633
18,000
8,054
<LONG-TERM-DEBT-NET> 108,834
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
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<TOT-CAPITALIZATION-AND-LIAB> 517,181
<GROSS-OPERATING-REVENUE> 219,886
<INCOME-TAX-EXPENSE> 1,837
<OTHER-OPERATING-EXPENSES> 210,518
<TOTAL-OPERATING-EXPENSES> 212,355
<OPERATING-INCOME-LOSS> 7,531
<OTHER-INCOME-NET> 4,098
<INCOME-BEFORE-INTEREST-EXPEN> 11,629
<TOTAL-INTEREST-EXPENSE> 7,919
<NET-INCOME> 4,583
1,459
<EARNINGS-AVAILABLE-FOR-COMM> 3,124
<COMMON-STOCK-DIVIDENDS> 5,082
<TOTAL-INTEREST-ON-BONDS> 6,030
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<EPS-PRIMARY> .27
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