SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
Form 10-Q
x QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 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 April 30, 1998
there were outstanding 11,425,651 shares of Common Stock, $6 Par Value.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Form 10-Q
Table of Contents
Page
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statement of Income and Retained Earnings
for the three months ended March 31, 1998 and 1997 3
Consolidated Balance Sheet as of March 31, 1998 and
December 31, 1997 4
Consolidated Statement of Cash Flows for the three
months ended March 31, 1998 and 1997 5
Notes to Consolidated Financial Statements 6-11
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 12-24
PART II. OTHER INFORMATION 25-26
SIGNATURE 27
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CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENT OF INCOME AND RETAINED EARNINGS
(Dollars in thousands, except per share amounts)
(Unaudited)
Three Months Ended
March 31
1998 1997
---- ----
Operating Revenues $83,958 $88,494
------- -------
Operating Expenses
Operation
Purchased power 39,706 40,996
Production and transmission 5,588 5,677
Other operation 11,434 9,985
Maintenance 3,852 3,041
Depreciation 4,227 4,460
Other taxes, principally property taxes 3,040 2,988
Taxes on income 5,432 7,207
------- -------
Total operating expenses 73,279 74,354
------- -------
Operating Income 10,679 14,140
------- -------
Other Income and Deductions
Equity in earnings of affiliates 732 885
Allowance for equity funds during construction 17 20
Other income, net 578 2,733
Provision for income taxes 10 (882)
------- -------
Total other income and deductions, net 1,337 2,756
------- -------
Total Operating and Other Income 12,016 16,896
------- -------
Interest Expense
Interest on long-term debt 2,531 2,511
Other interest 103 74
Allowance for borrowed funds during construction (9) (8)
------- -------
Total interest expense, net 2,625 2,577
------- -------
Net Income Before Extraordinary Credit 9,391 14,319
Extraordinary Credit Net of Taxes 873 -
------- -------
Net Income 10,264 14,319
Retained Earnings at Beginning of Period 75,841 74,137
------- -------
86,105 88,456
Cash Dividends Declared
Preferred stock 486 507
Common stock 6 2,534
------- -------
Total dividends declared 492 3,041
------- -------
Retained Earnings at End of Period $85,613 $85,415
======= =======
Earnings Available For Common Stock $ 9,778 $13,812
Average Shares of Common Stock Outstanding 11,423,951 11,519,748
Basic and Diluted Share of Common Stock:
Earnings before extraordinary credit $.78 $1.20
Extraordinary credit .08 -
---- -----
Earnings Per Basic and Diluted Share of Common Stock $.86 $1.20
==== =====
Dividends Paid Per Share of Common Stock $.22 $.22
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED BALANCE SHEET
(Dollars in thousands)
March 31 December 31
1998 1997
---- ----
Assets
Utility Plant, at original cost $461,764 $461,482
Less accumulated depreciation 155,354 151,250
-------- --------
306,410 310,232
Construction work in progress 12,818 10,450
Nuclear fuel, net 947 964
-------- --------
Net utility plant 320,175 321,646
-------- --------
Investments and Other Assets
Investments in affiliates, at equity 26,562 26,495
Non-utility investments 34,330 33,736
Non-utility property, less accumulated depreciation 2,848 2,894
-------- --------
Total investments and other assets 63,740 63,125
-------- --------
Current Assets
Cash and cash equivalents 25,949 16,506
Special deposits 432 404
Accounts receivable, less allowance for uncollectible
accounts ($1,950 in 1998 and $1,946 in 1997) 25,832 23,166
Unbilled revenues 12,359 18,951
Materials and supplies, at average cost 3,772 3,779
Prepayments 2,000 1,464
Other current assets 5,059 4,970
-------- --------
Total current assets 75,403 69,240
-------- --------
Regulatory Assets 72,848 73,209
-------- --------
Other Deferred Charges 5,133 4,720
-------- --------
Total Assets $537,299 $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 45,302 45,295
Treasury stock (360,197 shares and 362,447 shares,
respectively, at cost) (4,699) (4,728)
Retained earnings 85,613 75,841
-------- --------
Total common stock equity 196,931 187,123
Preferred and preference stock 8,054 8,054
Preferred stock with sinking fund requirements 18,000 19,000
Long-term debt 108,844 93,099
Long-term lease arrangements 16,952 17,223
-------- --------
Total capitalization 348,781 324,499
-------- --------
Current Liabilities
Short-term debt 250 12,650
Current portion of long-term debt and preferred stock 21,521 24,271
Accounts payable 5,349 4,609
Accounts payable - affiliates 14,622 12,441
Accrued income taxes 4,461 6,631
Dividends declared 486 2,513
Nuclear decommissioning costs 6,010 6,010
Other current liabilities 18,927 21,646
-------- --------
Total current liabilities 71,626 90,771
-------- --------
Deferred Credits
Deferred income taxes 56,100 53,996
Deferred investment tax credits 7,125 7,222
Nuclear decommissioning costs 27,381 28,947
Other deferred credits 26,286 26,505
-------- --------
Total deferred credits 116,892 116,670
-------- --------
Total Capitalization and Liabilities $537,299 $531,940
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)
(Unaudited)
Three Months Ended
March 31
1998 1997
---- ----
Cash Flows Provided (Used) By
Operating Activities
Net income $10,264 $14,319
Adjustments to reconcile net income to net cash
provided by operating activities
Equity in earnings of affiliates (732) (885)
Dividends received from affiliates 618 893
Equity in earnings of non-utility investments (1,659) (1,281)
Distribution of earnings from non-utility
investments 1,184 614
Extraordinary credit (873) -
Depreciation 4,227 4,460
Deferred income taxes and investment tax credits 1,723 333
Allowance for equity funds during construction (17) (20)
Net deferral and amortization of nuclear refueling
replacement energy and maintenance costs (1,345) 1,409
Amortization of conservation and load management
costs 1,755 1,755
Gain on sale of property - (2,095)
Decrease in accounts receivable and unbilled
revenues 4,482 329
Increase (decrease) in accounts payable 3,364 (802)
Increase (decrease) in accrued income taxes (2,171) 6,714
Change in other working capital items (3,531) 3,141
Other, net (933) (727)
------- -------
Net cash provided by operating activities 16,356 28,157
------- -------
Investing Activities
Construction and plant expenditures (3,242) (3,399)
Deferred conservation & load management expenditures (568) (575)
Return of capital 47 47
Proceeds from sale of property - 2,210
Non-utility investments (100) (776)
Other investments, net (156) (120)
------- -------
Net cash used for investing activities (4,019) (2,613)
------- -------
Financing Activities
Short-term debt, net (400) (5,750)
Long-term debt, net (5) (5)
Common and preferred dividends paid (2,518) (3,041)
Sale of treasury stock 29 -
------- -------
Net cash used for financing activities (2,894) (8,796)
------- -------
Net Increase in Cash and Cash Equivalents 9,443 16,748
Cash and Cash Equivalents at Beginning of Period 16,506 6,365
------- -------
Cash and Cash Equivalents at End of Period $25,949 $23,113
======= =======
Supplemental Cash Flow Information
Cash paid during the period for:
Interest (net of amounts capitalized) $ 586 $ 303
Income taxes (net of refunds) $ 5,851 $ 1,251
The accompanying notes are an integral part of these consolidated financial
statements.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 1998
Note 1 - Accounting Policies
The Company's significant accounting policies are described in Note 1 of
Notes to Consolidated Financial Statements included in its 1997 Annual Report
on Form 10-K filed with the Securities and Exchange Commission. For interim
reporting purposes, the Company follows these same basic accounting policies
but considers each interim period as an integral part of an annual period.
See Note 3 below for detail in regard to a Court Order issued on April 9, 1998
by the United States Court for the District of New Hampshire, sitting in
Rhode Island (Court) which again qualifies Connecticut Valley Electric Company
Inc. (Connecticut Valley), the Company's New Hampshire subsidiary, to prepare
its financial statements in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71.
RECLASSIFICATION Certain reclassifications have been made to prior year
Consolidated Financial Statements to conform with the 1998 presentation.
The financial information included herein is unaudited; however, such
information reflects all adjustments (consisting of normal recurring accruals)
which are, in the opinion of management, necessary for a fair statement of
results for the interim periods.
Note 2 - Environmental
The Company is engaged in various operations and activities which subject
it to inspection and supervision by both federal and state regulatory
authorities including the United States Environmental Protection Agency (EPA).
It is Company policy to comply with all environmental laws. The Company has
implemented various procedures and internal controls to assess and assure
compliance. If non-compliance is discovered, corrective action is taken.
Based on these efforts and the oversight of those regulatory agencies having
jurisdiction, the Company believes it is in compliance, in all material
respects, with all pertinent environmental laws and regulations.
Company operations occasionally result in unavoidable, inadvertent
releases of regulated substances or materials, for example the rupture of a
pole mounted transformer, or a broken hydraulic line. Whenever the Company
learns of such a release, the Company responds in a timely fashion and in a
manner that complies with all federal and state requirements. Except as
discussed in the following paragraphs, the Company is not aware of any
instances where it has caused, permitted or suffered a release or spill on or
about its properties or otherwise which is likely to result in any material
environmental liabilities to the Company.
The Company is an amalgamation of more than 100 predecessor companies.
Those companies engaged in various operations and activities prior to being
merged into the Company. At least two of these companies were involved in the
production of gas from coal to sell and distribute to retail customers at
three different locations. These activities were discontinued by the Company
in the late 1940's or early 1950's. The coal gas manufacturers, other
predecessor companies, and the Company itself may have engaged in waste
disposal activities which, while legal and consistent with commercially
accepted practices at the time, may not meet modern standards and thus
represent potential liability.
The Company continues to investigate, evaluate, monitor and, where
appropriate, remediate contaminated sites related to these historic
activities. The Company's policy is to accrue a liability for those sites
where costs for remediation, monitoring and other future activities are
probable and can be reasonably estimated. As part of that process, the
Company also researches the possibility of insurance coverage that could
defray any such remediation expenses. For related information see Part II
Item 1, Legal Proceedings below.
CLEVELAND AVENUE PROPERTY One such site is the Company's Cleveland Avenue
property located in the City of Rutland, Vermont, a site where one of its
predecessors operated a coal-gasification facility and later the Company sited
various operations functions. Due to the presence of coal tar deposits and
Polychlorinated Biphenyl (PCB) contamination and uncertainties as to potential
off-site migration of those contaminants, the Company conducted studies in the
late 1980's and early 1990's to determine the magnitude and extent of the
contamination. After completing its preliminary investigation, the Company
engaged a consultant to assist in evaluating clean-up methodologies and
provide cost estimates. Those studies indicated the cost to remediate the
site would be approximately $5 million. This was charged to expense in the
fourth quarter of 1992. Site investigation continued over the next several
years.
In January of 1995, the Company was formally contacted by the EPA asking
for written consent to conduct a site evaluation of the Cleveland Avenue
property. That evaluation has been completed. The Company does not believe
the EPA's evaluation changes its potential liability so long as the State
remains satisfied that reasonable progress continues to be made in remediating
the site and retains oversight of the process.
In 1995, as part of that process, the Company's consultant completed its
risk assessment report and submitted it to the State of Vermont for review.
The State generally agreed with that assessment but expressed a number of
concerns and directed the Company to collect some additional data. The
Company has addressed almost all of the concerns expressed by the State and
continues to work with the State in a joint effort to develop a mutually
acceptable solution.
The Company selected a consulting/engineering firm to collect the
additional data requested by the State and develop and implement a remediation
plan for the site. That firm has begun work at the site. It has collected
the additional data requested by the State and will use all the data gathered
to date to formulate a comprehensive remediation plan. The additional data
gathered to date has not caused the Company to alter its original estimate of
the likely cost of remediating the site.
PCB, INC. AND OSAGE METALS In August 1995, the Company received an
Information Request from the EPA pursuant to a Superfund investigation of
three related sites, located in Kansas and in Missouri (the Sites). During
the mid-1980's, these Sites received materials containing PCBs from hundreds
of sources, including the Company. According to the EPA, more than 1,200
parties have been identified as Potential Responsible Parties (PRPs). The
Company has complied with the information request and will monitor EPA
activities at the Sites.
In December 1996, the Company received an invitation to join a PRP
steering committee. The Company has not yet decided whether joining that
committee would be in its best interest. That committee has estimated the
Company's pro rata share of the waste sent to the Sites to be .42%. The
committee estimates that the Sites' remediation will cost between $5 million
and $40 million. Based on this information, the Company does not believe
that the Sites represent the potential for a material adverse effect on its
financial condition or results of operations.
PARKER LANDFILL AND THE TRAFTON-HOISINGTON LANDFILL The Company also faces
potential liability arising from the alleged disposal of hazardous materials
at these two former municipal landfills.
There have been no further developments involving the Company at these
two sites. The Company's investigations at the time it was originally
contacted indicated that it contributed little if any hazardous substances to
the sites. The Company has not been contacted by the EPA, the State or any of
the PRPs since 1994. Therefore, the Company believes that the likelihood that
these sites will cause the Company to accrue significant liability has
significantly diminished. At this time, the Company does not believe the
landfill sites represent the potential for a material adverse effect on its
financial condition or results of operations but it will continue to monitor
activities at the sites. The Company is not subject to any pending or
threatened litigation with respect to any other sites that have the potential
for causing the Company to incur material remediation expenses, nor has the
EPA or other federal or state agency sought contribution from the Company for
the study or remediation of any such sites.
In 1996, the Company filed a lawsuit in federal court against a number of
insurance companies. In its complaint, the Company alleges that general
liability policies issued by the insurers provide coverage for all expenses
incurred or to be incurred by the Company in conjunction with, among others,
the Cleveland Avenue Property. Settlements have been reached with all but one
defendant, with whom the Company has reached a settlement in principle. Due
to the uncertainties associated with the outcome of this lawsuit related to
the remaining defendant and the actual clean-up costs, the proceeds have been
applied to the environmental reserve.
Note 3 - Retail Rates
Vermont: The Company's practice of reviewing costs periodically will
continue and rate increases will be requested when warranted. The Company
filed for a 6.6% or $15.4 million general rate increase on September 22, 1997
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 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 have sought to challenge the
Company's decision in 1991 to "lock-in" its participation in its power
purchase agreement with Hydro-Quebec as one of 14 members of the Vermont Joint
Owners (VJO) claiming that the decision of the Company to commit to the power
contract in 1991 was imprudent and that power now purchased pursuant to that
agreement is not "used and useful." The parties have also claimed that the
Company has not met a condition of the Vermont Public Service Board's (PSB)
prior approval of the contract, requiring that the Company obtain all cost
effective Demand Side Management. In response, the Company filed a motion
asking the PSB to rule that any prudence and used and useful issues were
resolved in prior proceedings and that the PSB is precluded from again trying
the Company on those issues.
On April 17, 1998, the PSB issued an order generally denying the
Company's motion. Given the fact that the PSB had recently severely penalized
another VJO member, Green Mountain Power Corporation, in an Order dated
February 27, 1998, after finding that its decision to lock-in the Hydro-Quebec
contract was imprudent and the power purchased pursuant to that lock-in was
not used and useful, the Company concluded that it was necessary to have the
so-called preclusion issue reviewed by the Vermont Supreme Court (VSC) before
the PSB issues a final order in the Company's current rate case. As such, the
Company and other parties have 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.
Because the appeal and associated stay of the rate case will
significantly delay the date that the Company could increase rates, the
Company's revenues and earnings' prospects for 1998 will be adversely
affected. In an effort to mitigate the result, the Company expects to file
with the PSB a request for additional rate relief. The nature, magnitude and
timing of such a request has not yet been determined.
New Hampshire: On November 26, 1997, Connecticut Valley filed a request
with the New Hampshire Public Utilities Commission (NHPUC) to increase the
Fuel Adjustment Clause (FAC), Purchased Power Cost Adjustment (PPCA) and
short-term energy purchase rates effective on or after January 1, 1998. The
requested increase in rates results from higher forecast energy and capacity
charges on power Connecticut Valley purchases from the Company plus removal of
credit effective during 1997 to refund overcollections from 1996.
In an order dated December 31, 1997, the NHPUC directed Connecticut
Valley to freeze its current FAC and PPCA rates (other than short-term rates
to be paid to certain Qualifying Facilities) effective January 1, 1998, on a
temporary basis pending a hearing to determine: 1) the appropriate proxy for a
market price that Connecticut Valley could have obtained if it had terminated
its wholesale contract with the Company; 2) the implications of allowing
Connecticut Valley to pass on to its customers only that market price; and
3) whether the NHPUC's final determination on the FAC and PPCA rates should be
reconciled back to January 1, 1998 or some other date.
On January 19, 1998, Connecticut Valley and the Company (Companies) filed
with the Court for a temporary restraining order to maintain the status quo
ante by staying the NHPUC Order of December 31, 1997 and preventing the NHPUC
from taking any action that (i) compromises cost-based rate making for
Connecticut Valley; (ii) interferes with the Federal Energy Regulatory
Commission's (FERC) exclusive jurisdiction over the Company's pending
application to recover wholesale stranded costs upon termination of its
wholesale power contract with Connecticut Valley; or (iii) prevents
Connecticut Valley from recovering through retail rates the stranded costs and
purchased power costs that it incurs pursuant to its FERC-authorized wholesale
rate schedule with the Company.
On March 20, 1998, the NHPUC issued an order which affirms, clarifies and
modifies various generic policy statements including the reaffirmation to
establish rates on the basis of a regional average announced previously in its
February 28, 1997 Final Plan. The March 20, 1998 order also addresses all
outstanding motions for rehearings or clarification relative to the policies
or legal positions articulated in the Final Plan and removes the stay covering
the Company's interim stranded cost order of April 7, 1997. In addition, the
March 20, 1998 Order imposed various compliance filing requirements.
On April 3, 1998, the Court held a hearing on the Companies' motion for a
Temporary Restraining Order (TRO) and Preliminary Injunction against the NHPUC
at which time both the Companies and the NHPUC presented arguments. In an
oral ruling issued from the bench, which was continued in a written order
issued on April 9, 1998, the Court concluded that the Companies had
established each of the prerequisites for preliminary injunctive relief and
directed and required the NHPUC to allow Connecticut Valley to recover through
retail rates all costs for wholesale power requirements service that
Connecticut Valley purchases from the Company pursuant to its FERC-authorized
wholesale rate schedule effective January 1, 1998 until further court order.
Connecticut Valley has received an order from the NHPUC authorizing retail
rates to recover such costs beginning in May 1998. On April 14, 1998, the
NHPUC filed a notice of appeal and a motion for a stay of the Court's
preliminary injunction.
Also, on April 3, 1998, the Court indicated its TRO enjoining the NHPUC's
restructuring orders applied to Connecticut Valley and prohibits the
enforcement of the restructuring orders until the Court conducts a
consolidated hearing and rules on the requests for permanent injunctive relief
by plaintiff Public Service Company of New Hampshire (PSNH) and the other
utilities that have been allowed to intervene in these proceedings, including
the Company and Connecticut Valley. The plaintiffs-intervenors have 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. Subsequently, the NHPUC filed a motion to dismiss PSNH's
pending complaint on which the November hearing is scheduled. The Company has
sought leave of Court to file a brief in opposition to this motion.
As a result of these Court orders, Connecticut Valley's 1997 charges
under SFAS No. 5 and SFAS No. 71, described below in Management's Discussion
and Analysis of Financial Condition and Results of Operations - Electric
Industry Restructuring, were reversed in the first quarter of 1998. Combined,
the reversal of these charges increased first quarter 1998 net income and
earnings per share of common stock by approximately $4.5 million and $.39,
respectively.
On April 1, 1998, Citizens Bank of New Hampshire (Bank) notified
Connecticut Valley that it was in default of the Loan Agreement between the
Bank and Connecticut Valley dated December 27, 1994 and that the Bank will
exercise all of its remedies from and after May 5, 1998 in the event that the
violations are not cured. After reversing the 1997 write-offs described
above, Connecticut Valley will be in compliance with the financial covenants
associated with its $3.75 million loan with the Bank. As a result,
Connecticut Valley has satisfied the Bank's requirements for curing the
violation.
On May 11, 1998 the NHPUC issued an order requiring Connecticut Valley to
show cause why it should not be held in contempt for its failure to meet the
compliance filing requirements of its March 20, 1998 Order. A hearing on this
matter has been scheduled for June 11, 1998.
On June 25, 1997, the Company filed with the FERC a notice of termination
of its power supply contract with Connecticut Valley, conditional upon the
Company's request to impose a surcharge on the Company's transmission tariff
to recover the stranded costs that would result from the termination of its
contract with Connecticut Valley. The amount requested was $44.9 million plus
interest at the prime rate to be recovered over a ten-year period. In its
Order dated December 18, 1997 in Docket No. ER97-3435-000, the FERC rejected
the Company's proposed stranded cost surcharge mechanism but indicated that it
would consider an exit fee mechanism for collecting stranded costs. The FERC
also rejected the Company's arguments concerning the applicability of stated
FERC policies regarding retail stranded costs, multi-state regulatory gaps and
the implications of state restructuring initiatives. The Company has filed a
motion seeking rehearing of the FERC's December 18, 1997 Order. In addition,
and in accordance with the December 18, 1997 FERC Order, on January 12, 1998
the Company filed a request with the FERC for an exit fee mechanism to collect
$44.9 million in a lump sum, or in installments with interest at the prime
rate over a ten-year period, to cover the stranded costs resulting from the
cancellation of Connecticut Valley's power contract with the Company.
On March 11, 1998, the FERC issued an order accepting for filing the
Company's request for an exit fee effective March 14, 1998, and set hearings
to determine: whether Connecticut Valley will become an unbundled
transmission customer of the Company, the Company's expectation as to the
period of time it would serve Connecticut Valley, and the allowable amount of
the exit fee. The FERC also rejected the Company's June 25, 1997 notice of
termination indicating that the notice can be resubmitted when the power
contract is proposed to be terminated.
On April 28, 1998, the Company filed its case-in-chief before the FERC
updating the amount of the exit fee to $54.9 million in a lump sum, describing
all of the ways Connecticut Valley will become an unbundled transmission
customer of the Company subsequent to termination, and establishing the
expected period of service based upon the date of termination, whenever that
occurs, and the weighted average service life of its commitments to power
resources to serve Connecticut Valley. Had termination taken effect on
January 1, 1998 this expectation period would have equaled nineteen years.
If the Company is unable to obtain an order authorizing the full recovery
amount of the exit fee, or other appropriate mechanism, the Company would be
required to recognize a loss under SFAS No. 5 totaling approximately
$75.0 million on a pre-tax basis. Furthermore, the Company would be required
to write-off approximately $4.0 million in regulatory assets associated with
its wholesale business under SFAS No. 71 on a pre-tax basis. Conversely, even
if the Company obtains a FERC order authorizing the updated requested exit
fee, Connecticut Valley would be required to recognize a loss under SFAS No. 5
of approximately $54.9 million on a pre-tax basis unless Connecticut Valley
has obtained an order by the NHPUC or other appropriate body directing the
recovery of those costs in Connecticut Valley's retail rates. Either of these
reasonably possible outcomes could occur during calendar year 1998.
The Company has initiated and will continue to work for a negotiated
settlement with parties to the New Hampshire restructuring proceeding and the
NHPUC. The Company cannot predict the ultimate outcome of this matter.
However, an adverse resolution could have a material adverse effect on the
Company's results of operations, cash flows, and ability to obtain capital at
competitive rates.
Note 4 - Investment in Vermont Yankee Nuclear Power Corporation
The Company accounts for its investment in Vermont Yankee using the
equity method. Summarized financial information for Vermont Yankee Nuclear
Power Corporation follows:
Three Months Ended March 31
1998 1997
---- ----
Operating revenues $51,170 $40,421
Operating income $ 3,760 $ 3,711
Net income $ 1,702 $ 1,775
Company's equity in net income $510 $556
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
March 31, 1998
Earnings Overview
Earnings available for common stock and earnings per share of common
stock for the quarter ended March 31, 1998 were $9.8 million and $.86 compared
to $13.8 million and $1.20 for the corresponding period last year.
Earnings available for common stock and earnings per share of common
stock include the positive impact of the reversal of a fourth quarter 1997
charge of $3.6 million and $.31, respectively. This 1997 charge represented
the estimated loss on a FERC-approved power contract with the Company during
1998 at Connecticut Valley. The reversal of this 1997 charge results from a
federal court order issued on April 9, 1998. (See Electric Industry
Restructuring - New Hampshire below and Note 1 in Notes to Consolidated
Financial Statements for more information.) The court order directed the
NHPUC to allow Connecticut Valley to recover through retail rates all costs
for power it purchases from the Company pursuant to FERC-authorized rate
schedules. In addition, because the court order restores Connecticut Valley to
cost-based rate-making, net income and earnings per share of common stock for
the first quarter of 1998 were increased by an after-tax extraordinary credit
of $.9 million and $.08, respectively. This reverses a charge of a like
amount taken in the fourth quarter of 1997. Other factors affecting results
for 1998 are described in Results of Operations below.
Earnings for the first quarter of 1997 reflect a net of tax gain from
sale of property of approximately $1.3 million, or $.12 per share of common
stock.
RESULTS OF OPERATIONS
The major elements of the Consolidated Statement of Income are discussed
below.
Operating Revenues and MWH Sales
A summary of MWH sales and operating revenues for the three months ended
March 31, 1998 and 1997 (and the related percentage changes from 1997) is set
forth below:
<TABLE>
<CAPTION>
Three Months Ended March 31
------------------------------------------------
Percentage Percentage
MWH Increase Revenues (000's) Increase
1998 1997 (Decrease) 1998 1997 (Decrease)
------- ------- ---------- ------- ------- ----------
<S> <C> <C> <C> <C> <C> <C>
Residential 264,461 275,287 (3.9) $35,177 $35,803 (1.7)
Commercial 228,432 230,075 (.7) 27,462 30,400 (9.7)
Industrial 109,888 115,644 (5.0) 10,095 10,654 (5.2)
Other retail 1,802 1,763 2.2 483 471 2.5
------- ------- ------- -------
Total retail sales 604,583 622,769 (2.9) 73,217 77,328 (5.3)
------- ------- ------- -------
Resale sales:
Firm 674 265 154.3 19 11 72.7
Entitlement 85,012 110,863 (23.3) 4,984 4,955 .6
Other 170,089 195,375 (12.9) 4,604 4,807 (4.2)
------- ------- ------- -------
Total resale sales 255,775 306,503 (16.6) 9,607 9,773 (1.7)
------- ------- ------- -------
Other revenues - - - 1,134 1,393 (18.6)
------- ------- ------- -------
Total sales 860,358 929,272 (7.4) $83,958 $88,494 (5.1)
======= ======= ======= =======
</TABLE>
Retail MWH sales for the first quarter of 1998 decreased 2.9% compared to
the first quarter of 1997 reflecting moderate temperature not typical of a
Vermont winter. Retail revenues decreased $4.1 million , or 5.3% compared to
last year. This negative variance is attributable to a $2.1 million impact of
lower MWH sales in the first quarter of 1998 as compared to the first quarter
of 1997 and $2.0 million resulting from a modified rate design reflected in
bills rendered since April 1, 1997 which reduced the price charged per MWH
during the first quarter of 1998 compared to the 1997 quarter. The modified
rate design, which is revenue neutral on an annual basis, decreases prices
charged during the winter months of December through March and increases
prices during the remaining months of the year.
For the first quarter of 1998, entitlement MWH sales decreased 23.3%
while related revenues were about the same compared to the same period last
year.
The 25,286 MWH decrease ($.2 million) in other resale sales resulted
principally from decreased sales to NEPOOL and to other utilities in
New England partially offset by an increase in system capacity sales.
Due to lower revenues associated with pole attachment rentals, other
revenues decreased $.3 million for the first quarter of 1998 compared to the
same period last year.
Net Purchased Power and Production Fuel Costs
The net cost components of purchased power and production fuel costs for
the three months ended March 31, 1998 and 1997 are as follows (dollars in
thousands):
<TABLE>
<CAPTION>
1998 1997
Units Amount Units Amount
----- ------ ----- ------
<S> <C> <C> <C> <C>
Purchased and produced:
Capacity (MW) 569 $20,441 524 $21,288
Energy (MWH) 836,276 19,265 926,064 19,708
------- -------
Total purchased power costs 39,706 40,996
Production fuel (MWH) 75,075 515 60,726 266
------- -------
Total purchased power and
production fuel costs 40,221 41,262
Entitlement and other resale sales (MWH) 255,101 9,588 306,238 9,761
------- -------
Net purchased power and production
fuel costs $30,633 $31,501
======= =======
</TABLE>
Net purchased power and production fuel costs decreased $.9 million, or
2.8% for the first quarter of 1998 compared to the first quarter of 1997.
However, absent the benefit of the 1997 Connecticut Valley reversal discussed
above, net purchased power and production fuel costs increased $4.6 million,
or 14.7% for 1998 compared to the same period last year primarily as the
result of higher costs under the Hydro-Quebec power contract.
Pursuant to a Vermont Public Service Board (PSB) Accounting Order, first
quarter 1997 energy costs were reduced by approximately $2.9 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.
NUCLEAR MATTERS
The Company maintains a 1.7303% joint-ownership interest in the Millstone
Unit #3 of the Millstone Nuclear Power Station and owns a 2% equity interest
in Connecticut Yankee. These two plants are operated by Northeast Utilities
(NU). The Company also owns 2%, 3.5% and 31.3% equity interest in Maine
Yankee, Yankee Atomic and Vermont Yankee, respectively.
Millstone Unit #3
Millstone Unit #3 (Unit #3) has been out of service since March 30, 1996,
due to numerous technical and non-technical problems and is on the Nuclear
Regulatory Commission's (NRC) watch list. The Company's share of the total
incremental operating and maintenance costs for Unit #3 were about
$1.0 million for 1997 and are expected to be about $.3 million for 1998.
Incremental power costs for 1998 are estimated to be about $130,000 per month.
All comprehensive plans to restart Unit #3 are implemented and Unit #3 was
ready for NRC's operational safety inspection on April 13, 1998. The Company
anticipates Unit #3 to resume operations during the third quarter of 1998.
The Company remains actively involved with the other non-operating
minority joint-owners of Unit #3. This group is engaged in various activities
to monitor and evaluate NU and Northeast Utilities Service Co.'s efforts
relating to Unit #3. On August 7, 1997, the Company and eight other non-
operating owners of Unit #3 filed a demand for arbitration with Connecticut
Light and Power Company and Western Massachusetts Electric Company and
lawsuits against NU and its trustees. The arbitration and lawsuits seek to
recover costs associated with replacement power, operation and maintenance
costs and other costs resulting from the shutdown of Unit #3. The non-
operating owners claim that NU and two of its wholly owned subsidiaries failed
to comply with NRC's regulations, failed to operate the facility in accordance
with good operating practice and attempted to conceal their activities from
the non-operating owners and the NRC.
Maine Yankee
On August 6, 1997, the Maine Yankee's Nuclear Power plant was prematurely
retired from commercial operation. The Company relied on Maine Yankee for
less than 5% of its required system capacity.
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 is expected to return to service during May 1998. The Company
expects to defer approximately $1.8 million and $5.9 million for replacement
energy and maintenance costs, respectively. These deferrals will be amortized
to expense over eighteen months which is the expected in service period before
Vermont Yankee's next scheduled refueling outage.
The Design Basis Documentation project (Project) initiated by Vermont
Yankee during 1996 is expected to be completed by the end of year 2000. The
Company's 35% share of the total cost for this Project is expected to be about
$5.9 million. Such costs will be deferred by Vermont Yankee and amortized
over the remaining license life of the plant.
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 $16.6 million,
$12.4 million and $4.4 million, respectively. These amounts are subject to
ongoing review and revisions and are reflected in the accompanying balance
sheet both as regulatory assets and deferred power contract obligations
(current and non-current). Although the estimated costs of decommissioning
are subject to change due to changing technologies and regulations, the
Company expects that the nuclear generating companies' liability for
decommissioning, including any future changes in the liability, will be
recovered in their rates over their operating or license lives.
The decision to prematurely retire these nuclear power plants was based
on economic analyses of the costs of operating them compared to the costs of
closing them and incurring replacement power costs over the remaining period
of the plants' operating licenses. The Company believes that based on the
current regulatory process, its proportionate share of Maine Yankee,
Connecticut Yankee and Yankee Atomic decommissioning costs will be recovered
through the regulatory process and, therefore, the ultimate resolution of the
premature retirement of the three plants has not and will not have a material
adverse effect on the Company's earnings or financial condition.
Other Operation
Other operating expenses increased $1.4 million for the first quarter of
1998 compared to the first quarter of 1997 principally due to increased
consulting and regulatory commission expenses.
Maintenance
The increase in maintenance expenses of $.8 million for the first quarter
of 1998 compared to the same period in 1997 is attributable to a severe ice
storm in January 1998.
Income Taxes
Federal and state income taxes fluctuate with the level of pre-tax
earnings. The decrease in total income tax expense for the first quarter of
1998 results primarily from a decrease in pre-tax earnings for the period.
Other Income and Deductions
Due to lower earnings from the Company's nuclear generating and
transmission affiliates, equity in earnings of affiliates decreased
$.2 million for the first quarter of 1998 compared to the same period in 1997.
The decrease in other income, net for the 1998 first quarter results
primarily from a gain of $1.3 million from a non-recurring asset sale in
February 1997.
Extraordinary Credit
The extraordinary credit net of taxes of $.9 million represents a
reversal of a charge of a like amount taken in the fourth quarter of 1997
discussed above.
Dividends Declared
The decrease in common dividends declared results from an early
declaration made in December 1997 for the quarterly dividend paid on
February 13, 1998.
LIQUIDITY AND CAPITAL RESOURCES
Construction - 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 provided by operating activities
generated $16.3 million and $28.2 million for the three months ended March 31,
1998 and 1997, respectively.
The Company ended the first three months of 1998 with cash and cash
equivalents of $25.9 million, an increase of $9.4 million from the beginning
of the year. The increase in cash for the first three months of 1998 was the
result of $16.3 million provided by operating activities, $4.0 million used
for investing activities and $2.9 million used for financing activities.
Operating Activities - Net income, depreciation and deferred income taxes
and investment tax credits provided $16.2 million. About $.1 million of cash
was provided from fluctuations in working capital and other operating
activities.
Investing Activities - Construction and plant expenditures consumed
approximately $3.2 million, while $.8 million was used for C&LM programs and
non-utility investments.
Financing Activities - Dividends paid on common stock were $2.5 million,
while short-term obligations required $.4 million.
For related information see the Company's discussion on Financing and
Capitalization below.
ELECTRIC INDUSTRY RESTRUCTURING
The electric utility industry is in a period of transition that may
result in a shift away from ratemaking based on cost of service and return on
equity to more market-based rates. Many states, including Vermont and
New Hampshire, where the Company does business, are exploring new mechanisms
to bring greater competition, customer choice and market influence to the
industry while retaining the public benefits associated with the current
regulatory system.
Vermont
On December 31, 1996, the PSB issued a Report and Order (the Report)
outlining a restructuring plan (the Plan), subject to legislative approval,
for the Vermont electric utility industry.
Due to uncertainty surrounding legislative schedules, the PSB, on
April 18, 1997, issued an Order which suspended, pending further legislative
action or future PSB Orders, certain filing deadlines for reports and plans to
be completed in connection with the Plan.
In an effort to achieve a negotiated resolution to the issues surrounding
the restructuring of the Vermont electric utility industry, the Company, Green
Mountain Power Corporation, the Vermont Department of Public Service (DPS) and
representatives of the Governor of the State of Vermont developed a Memorandum
of Understanding (MOU) in February 1997 establishing a plan for implementing
restructuring in Vermont. That MOU expressly required legislative action to
become efficient. Although concepts of the MOU were considered by the Vermont
General Assembly, no action was taken on the MOU by the Legislature and the
MOU has now lapsed.
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 been 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 or the MOU.
Other legislation intended to advance a portion of the PSB Report and Order
and the MOU were 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,
the MOU, S.62 or the House Special Committee report.
New Hampshire
On February 28, 1997 the NHPUC published its detailed Final Plan to
restructure the electric utility industry in New Hampshire. Also on
February 28, 1997, the NHPUC, in a supplemental order specific to Connecticut
Valley, found that Connecticut Valley was imprudent for not terminating the
FERC-authorized power contract between Connecticut Valley and the Company,
required Connecticut Valley to give notice to cancel its contract with the
Company and denied stranded cost recovery related to this power contract.
Connecticut Valley filed for rehearing of the February 28, 1997 NHPUC Order.
On April 7, 1997, the NHPUC issued an Order addressing certain threshold
procedural matters raised in motions for rehearing and/or clarification filed
by various parties, including Connecticut Valley, relative to the Final Plan
and interim stranded cost orders. The April 7, 1997 Order stayed those
aspects of the Final Plan that were the subject of rehearing or clarification
requests and also stayed the interim stranded cost orders for the various
parties, including Connecticut Valley. As such, those matters pertaining to
the power contract between Connecticut Valley and the Company were stayed.
The suspension of these orders was to remain in effect until two weeks
following the issuance of any order concerning outstanding requests for
rehearing and clarification.
On March 20, 1998, the NHPUC issued an order which affirms, clarifies and
modifies various generic policy statements including the reaffirmation to
establish rates on the basis of a regional average announced previously in its
February 28, 1997 Final Plan. The March 20, 1998 order also addressed all
outstanding motions for rehearings or clarification relative to the policies
or legal positions articulated in the Final Plan and removes the stay covering
the Company's interim stranded cost order of April 7, 1997. In addition, the
March 20, 1998 Order imposed various compliance filing requirements.
On November 17, 1997, the City of Claremont, New Hampshire (Claremont),
filed with the NHPUC a petition for a reduction in Connecticut Valley's
electric rates. Claremont based its request on the NHPUC's earlier finding
that Connecticut Valley's failure to terminate its wholesale power contract
with the Company as ordered in the NHPUC Stranded Cost Order of February 28,
1997 was imprudent. Under the wholesale power purchase contract with the
Company, Connecticut Valley may terminate service at the end of a service
year, provided it has given written notice of termination prior to the
beginning of that service year. Claremont alleges that if Connecticut Valley
had given written notice of termination to the Company in 1996 when
legislation to restructure the electric industry was enacted in New Hampshire,
Connecticut Valley's obligation to purchase power from the Company would have
terminated as of January 1, 1998.
On November 26, 1997, Connecticut Valley filed a request with the NHPUC
to increase the FAC, PPCA and short-term energy purchase rates effective on or
after January 1, 1998. The requested increase in rates resulted from higher
forecast energy and capacity charges on power Connecticut Valley purchases
from the Company plus removal of a credit effective during 1997 to refund
overcollections from 1996. Connecticut Valley objected to the NHPUC's notice
of intent to consolidate Claremont's petition into the FAC and PPCA docket,
stating that Claremont's complaint should be heard as part of the NHPUC
restructuring docket. Over Connecticut Valley's objection at the hearing on
December 17, 1997, the NHPUC consolidated Claremont's petition with
Connecticut Valley's FAC and PPCA proceeding.
In an Order dated December 31, 1997 in Connecticut Valley's FAC and PPCA
docket, the NHPUC found Connecticut Valley acted imprudently by not
terminating the wholesale contract between Connecticut Valley and the Company,
notwithstanding the stays of its February 28, 1997 Orders. The NHPUC Order
further directed Connecticut Valley to freeze its current FAC and PPCA rates
(other than short term rates to be paid to certain Qualifying Facilities)
effective January 1, 1998, on a temporary basis, pending a hearing to
determine: 1) the appropriate proxy for a market price that Connecticut Valley
could have obtained if it had terminated its wholesale contract with the
Company; 2) the implications of allowing Connecticut Valley to pass on to its
customers only that market price; and 3) whether the NHPUC's final
determination on the FAC and PPCA rates should be reconciled back to
January 1, 1998 or some other date.
On January 19, 1998, Connecticut Valley and the Company filed with the
Federal District Court for a temporary restraining order to maintain the
status quo ante by staying the December 31, 1997 NHPUC Order and preventing
the NHPUC from taking any action that (i) compromises cost-based rate making
for Connecticut Valley or otherwise seeks to impose market price-based rate
making on Connecticut Valley; (ii) interferes with the FERC's exclusive
jurisdiction over the Company's pending application to recover wholesale
stranded costs upon termination of its wholesale power contract with
Connecticut Valley; or (iii) prevents Connecticut Valley from recovering
through retail rates the stranded costs and purchased power costs that it
incurs pursuant to its FERC-authorized wholesale rate schedule with the
Company.
On February 23, 1998, the NHPUC announced from the bench that it
reaffirmed its finding of imprudence and would designate a proxy market price
for power at 4 cents per kWh in lieu of the actual costs incurred pursuant to
the wholesale power contract with the Company. In addition, the NHPUC
indicated, subject to certain conditions, 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 from the bench, 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 issued from the bench, which was continued in a written order
issued on April 9, 1998, the Court concluded that the Companies had
established each of the prerequisites for preliminary injunctive relief and
directed and required the NHPUC to allow Connecticut Valley to recover through
retail rates all costs for wholesale power requirements service that
Connecticut Valley purchases from the Company pursuant to its FERC-authorized
wholesale rate schedule effective January 1, 1998 until further court order.
Connecticut Valley has received an order from the NHPUC authorizing retail
rates to recover such costs beginning in May 1998. On April 14, 1998, the
NHPUC filed a notice of appeal and a motion for a stay of the Court's
preliminary injunction.
Also, on April 3, 1998, the Court indicated its TRO enjoining the NHPUC's
restructuring orders applied to Connecticut Valley and prohibits the
enforcement of the restructuring orders until the Court conducts a
consolidated hearing and rules on the requests for permanent injunctive relief
by plaintiff PSNH and the other utilities that have been allowed to intervene
in these proceedings, including the Company and Connecticut Valley. The
plaintiffs-intervenors have 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. Subsequently, the NHPUC
has filed a motion to dismiss PSNH's pending complaint on which the November
hearing is scheduled. The Company has sought leave of Court to file a brief
in opposition to this motion.
As a result of these Court orders, Connecticut Valley's 1997 charges
under SFAS No. 5 and SFAS No. 71 described above were reversed in the first
quarter of 1998. Combined, the reversal of these charges increased
first quarter 1998 net income and earnings per share of common stock by
approximately $4.5 million and $.39, respectively.
On April 1, 1998, Citizens Bank of New Hampshire (Bank) notified
Connecticut Valley that it was in default of the Loan Agreement between the
Bank and Connecticut Valley dated December 27, 1994 and that the Bank will
exercise all of its remedies from and after May 5, 1998 in the event that the
violations are not cured. After reversing the 1997 write-offs described
above, Connecticut Valley will be in compliance with the financial covenants
associated with its $3.75 million loan with the Bank. As a result,
Connecticut Valley has satisfied the Bank's requirements for curing the
violation.
On May 11, 1998 the NHPUC issued an order requiring the Company 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 has
been scheduled in this matter on June 11, 1998.
On June 25, 1997, the Company filed with the FERC a notice of termination
of its power supply contract with Connecticut Valley, conditional upon the
Company's request to impose a surcharge on the Company's transmission tariff
to recover the stranded costs that would result from the termination of its
contract with Connecticut Valley. The amount requested was $44.9 million plus
interest at the prime rate to be recovered over a ten-year period. In its
Order dated December 18, 1997 in Docket No. ER97-3435-000, the FERC rejected
the Company's proposed stranded cost surcharge mechanism but indicated that it
would consider an exit fee mechanism for collecting stranded costs. The FERC
also rejected the Company's arguments concerning the applicability of stated
FERC policies regarding retail stranded costs, multi-state regulatory gaps and
the implications of state restructuring initiatives. The Company has filed a
motion seeking rehearing of the FERC's December 18, 1997 Order. In addition,
and in accordance with the December 18, 1997 FERC Order, on January 12, 1998
the Company filed a request with the FERC for an exit fee mechanism to collect
$44.9 million in a lump sum, or in installments with interest at the prime
rate over a ten-year period, to cover the stranded costs resulting from the
cancellation of Connecticut Valley's power contract with the Company.
On March 11, 1998, the FERC issued an order accepting for filing the
Company's request for an exit fee effective March 14, 1998, and set hearings
to determine: whether Connecticut Valley will become an unbundled
transmission customer of the Company, the Company's expectation as to the
period of time it would serve Connecticut Valley, and the allowable amount of
the exit fee. The FERC also rejected the Company's June 25, 1997 notice of
termination indicating that the notice can be resubmitted when the power
contract is proposed to be terminated.
On April 28, 1998, the Company filed its case-in-chief before the FERC
updating the amount of the exit fee to $54.9 million in a lump sum, describing
all of the ways Connecticut Valley will become an unbundled transmission
customer of the Company subsequent to termination, and establishing the
expected period of service based upon the date of termination, whenever that
occurs, and the weighted average service life of its commitments to power
resources to serve Connecticut Valley. Had termination taken effect on
January 1, 1998 this expectation period would have equaled nineteen years.
If the Company is unable to obtain an order authorizing the full recovery
amount of the exit fee, or other appropriate mechanism, the Company would be
required to recognize a loss under SFAS No. 5 totaling approximately $75.0
million on a pre-tax basis. Furthermore, the Company would be required to
write-off approximately $4.0 million in regulatory assets associated with its
wholesale business under SFAS No. 71 on a pre-tax basis. Conversely, even if
the Company obtains a FERC order authorizing the updated requested exit fee,
Connecticut Valley would be required to recognize a loss under SFAS No. 5 of
approximately $54.9 million on a pre-tax basis unless Connecticut Valley has
obtained an order by the NHPUC or other appropriate body directing the
recovery of those costs in Connecticut Valley's retail rates. Either of these
reasonably possible outcomes could occur during calendar year 1998.
For further information on New Hampshire restructuring issues and other
regulatory events in New Hampshire affecting the Company or Connecticut Valley
and the December 1997 charges and reversals of the charges, see the Company's
Form 8-K dated January 12, 1998, January 28, 1998 and April 1, 1998; and Item
1. Business-New Hampshire Retail Rates, Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations-Electric Industry
Restructuring-New Hampshire and Item 8. Financial Statements and Supplementary
Data-Note 13, Retail Rates-New Hampshire in the Company's 1997 Form 10-K.
The Company has initiated and will continue to work for a negotiated
settlement with parties to the New Hampshire restructuring proceeding and the
NHPUC. The Company cannot predict the ultimate outcome of this matter.
However, an adverse resolution could have a material adverse effect on the
Company's results of operations, cash flows, and ability to obtain capital at
competitive rates.
Connecticut Valley constitutes approximately 7% of the Company's total
retail MWH sales.
Competition-Risk Factors
If retail competition is implemented in Vermont or New Hampshire, the
Company is unable to predict the impact of this competition on its revenues,
the Company's ability to retain existing customers and attract new customers
or the margins that will be realized on retail sales of electricity.
Historically, electric utility rates have been based on a utility's
costs. As a result, electric utilities are subject to certain accounting
standards that are not applicable to other business enterprises in general.
SFAS No. 71 requires regulated entities, in appropriate circumstances, to
establish regulatory assets and liabilities, and thereby defer the income
statement impact of certain costs and revenues that are expected to be
realized in future rates.
As described in Note 1 of Notes to Consolidated Financial Statements,
included in this Quarterly Report on Form 10-Q, the Company believes it
currently complies with the provisions of SFAS No. 71 for its regulated retail
and FERC regulated wholesale businesses. In the event the Company determines
that it no longer meets the criteria for following SFAS No. 71, the accounting
impact would be an extraordinary, non-cash charge to operations of
approximately $73.0 million on a pre-tax basis as of March 31, 1998. Criteria
that give rise to the discontinuance of SFAS No. 71 include (1) increasing
competition that restricts the Company's ability to establish prices to
recover specific costs and (2) a significant change in the manner in which
rates are set by regulators from cost-based regulation to another form of
regulation.
The Securities and Exchange Commission has questioned the ability of
certain utility companies continuing the application of SFAS No. 71 where
legislation provides for the transition to retail competition. Deregulation
of the price of electricity issues related to the application of SFAS No. 71
and 101, as to when and how to discontinue the application of SFAS No. 71 by
utilities during transition to competition has been referred to the Financial
Accounting Standards Board's Emerging Issues Task Force (EITF).
The EITF has reached a tentative consensus, and no further discussion is
planned, that regulatory assets should be assigned to separable portions of
the Company's business based on the source of the cash flows that will recover
those regulatory assets. Therefore, if the source of the cash flows is from a
separable portion of the Company's business that meets the criteria to apply
SFAS No. 71, those regulatory assets should not be written off under SFAS
No. 101, "Accounting for the Discontinuation of Application of SFAS No. 71,"
but should be assessed under paragraph 9 of SFAS No. 71 for realizability.
SFAS No. 121, "Accounting for the Impairment of Long Lived Assets and for
Long-Lived Assets to Be Disposed Of," which was adopted by the Company on
January 1, 1996, requires that any assets, including regulatory assets, that
are no longer probable of recovery through future revenues, be revalued based
upon future cash flows. SFAS No. 121 requires that a rate-regulated
enterprise recognize an impairment loss for the amount of costs excluded from
recovery. As of December 31, 1997, based upon the regulatory environment
within which the Company currently operates, SFAS No. 121 did not have an
impact on the Company's financial position or results of operations.
Competitive influences or regulatory developments may impact this status in
the future.
Because the Company is unable to predict what form possible future
restructuring legislation will take, it cannot predict if or to what extent
SFAS Nos. 71 and 121 will continue to be applicable in the future. In
addition, if the Company is unable to mitigate or otherwise recover stranded
costs that could arise from any potentially adverse legislation or regulation,
the Company would have to assess the likelihood and magnitude of losses
incurred under SFAS No. 5.
As such, the Company cannot predict whether any restructuring legislation
enacted in Vermont or New Hampshire, once implemented, would have a material
adverse effect on the Company's operations, financial condition or credit
ratings. However, the Company's failure to recover a significant portion of
its purchased power costs, would likely have a material adverse effect on the
Company's results of operations, cash flows and ability to obtain capital at
competitive rates. It is possible that stranded cost exposure associated with
SFAS Nos. 5, 71, and 121, before mitigation could exceed the Company's current
total common stock equity.
FINANCING AND CAPITALIZATION
Utility
The level of short-term borrowings fluctuates based on seasonal corporate
needs, the timing of long-term financings and market conditions.
On November 5, 1997 the Company entered into an unsecured $50 million,
364 day committed Revolving Credit and Competitive Advance Facility (Credit
Facility) with a group of banks. With the approval of this facility by the
PSB on April 2, 1998, it became a three-year facility with two one-year
options. However, due to the February 27, 1998 Order issued by the PSB in the
Green Mountain Power Corporation rate proceeding, the banks participating in
this Credit Facility have determined that a material adverse change occurred
in the Company's financial prospects. Such a condition would prevent
borrowings under the Credit Facility. Currently, the Company has no
borrowings outstanding under this Credit Facility.
Negotiations with the banks participating in the Credit Facility have
resulted in an understanding, subject to documentation and regulatory
approval, of modifications to the Credit Facility. Those major changes are:
1) a second mortgage interest in the Company's Vermont utility fixed assets;
2) a revised maturity date of June 1, 1999 (the original agreement was to end
in November 2000); 3) a 25 basis point increase in interest rates on
borrowings; 4) the application of any proceeds from the issuance of any First
Mortgage Bonds during the term of the Credit Facility to the concurrent
repayment of any outstanding loans as well as the reduction of the aggregate
commitment of the Credit Facility; and 5) a 25 basis point increase in the
cost of $16.3 million aggregate notional amount of letters of credit.
Although the Company expects borrowings under the Credit Facility will
again become available shortly, it cannot guarantee the availability of the
Credit Facility to meet near-term liquidity needs. In December 1998
approximately $20.5 million of long-term debt becomes due and payable.
Connecticut Valley maintains a $.8 million committed line of credit for
its construction program and for other corporate purposes which expires on
May 31, 1998. Interest rates for borrowings under this short-term debt
arrangement are 25 basis points less than the prime rate. Connecticut Valley
had $250,000 and $625,000 outstanding short-term debt at March 31, 1998 and
December 31, 1997, respectively. Connecticut Valley is currently negotiating
with Citizens Bank of New Hampshire to extend this facility.
The Company's capital structure ratios as of March 31, 1998 (including
amounts of long-term debt due within one year) consisted of 53.2% common
equity, 7.0% preferred stock and 39.8% long-term debt including capital lease
obligations.
Current credit ratings of the Company's securities as reaffirmed by Duff
& Phelps and Standard & Poor's are as follows:
Duff & Standard
Phelps & Poor's
------ --------
First Mortgage Bonds BBB A-
Corporate Credit Rating BBB
Preferred Stock BBB- BBB-
On January 22, 1998, Standard & Poor's revised its ratings outlook on the
Company to negative from stable stating that the revised outlook reflects the
adverse ruling by the NHPUC related to Connecticut Valley discussed above.
Non-Utility
Catamount, a wholly owned subsidiary of the Company, implemented a credit
facility in July 1996 which provides for up to $8.0 million of letters of
credit and working capital loans. Currently, a $1.2 million letter of credit
is outstanding to support certain of Catamount's obligations in connection
with a debt reserve requirement in the Appomattox Cogeneration project.
Financial obligations of the non-utility wholly owned subsidiaries are
non-recourse to the Company.
C&LM Programs
The primary purpose of these programs is to offset the need for long-term
power supply and delivery resources that are more expensive to purchase or
develop than customer-efficiency programs. Total C&LM expenditures in 1997
were $2.7 million and are expected to be $1.7 million for 1998.
Diversification
Catamount was formed for the purpose of investing in non-regulated power
plant projects. Currently, Catamount, through its wholly owned subsidiaries,
has interests in five operating independent power projects located in Glenns
Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; and Hopewell,
Virginia. In addition, Catamount has interests in two projects under
construction in Thetford and Fort Dunlop, England, and a project under
development in Summersville, West Virginia. Catamount's after-tax earnings
were $.7 million and $.5 million for the first quarter 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 for the first quarter of 1998 and
earnings of $.04 million for the same period last year. The 1998 loss results
from activities that will allow SmartEnergy to enter several niches of the
national and international energy market. SmartEnergy has signed an agreement
to manufacture and deliver the SmartDrive dairy vacuum pump control to
domestic and worldwide markets beginning later this year. Allies in this
venture 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.
New Hampshire: On November 26, 1997, Connecticut Valley filed a request
with the NHPUC to increase the FAC, PPCA and short-term energy purchase rates
effective on or after January 1, 1998. The requested increase in rates
results from higher forecast energy and capacity charges on power Connecticut
Valley purchases from the Company plus removal of credit effective during 1997
to refund overcollections from 1996.
In an order dated December 31, 1997, the NHPUC directed Connecticut
Valley to freeze its current FAC and PPCA rates (other than short-term rates
to be paid to certain Qualifying Facilities) effective January 1, 1998, on a
temporary basis pending a hearing to determine: 1) the appropriate proxy for a
market price that Connecticut Valley could have obtained if it had terminated
its wholesale contract with the Company; 2) the implications of allowing
Connecticut Valley to pass on to its customers only that market price; and
3) whether the NHPUC's final determination on the FAC and PPCA rates should be
reconciled back to January 1, 1998 or some other date.
For additional information on Vermont and New Hampshire rate and
regulatory matters see Electric Industry Restructuring discussed above and
Note 3 to the Consolidated Financial Statements.
Year 2000 Information Systems Modifications
The Company has assessed the impact of the year 2000 issue on its
computer systems and applications. During 1997, the Company incurred costs of
approximately $.1 million and estimates that about $2.5 million will be
incurred in 1998 and $.2 million will be incurred in 1999 to modify its
existing computer systems and applications which are expected to be completed
during the second quarter of 1999. During the first quarter of 1998, the
Company requested an accounting order from the PSB to defer these operating
and maintenance costs. The Company believes that based on the current
regulatory process, these costs will be recovered through the regulatory
process and therefore they do not represent the potential for a material
adverse effect on its financial position or results of operations.
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 believes that the adoption of SOP 98-5 will not have a material
impact on the Company's financial position or results of operations.
Forward Looking Statements
Statements in this report relating to future financial conditions are
forward looking statements. Such forward-looking statements are not
guarantees of future performance and involve known and unknown risks,
uncertainties and other factors, which may cause the actual results,
performances or achievements to differ materially from the future forward-
looking statements. Such factors include general economic and business
conditions, changes in industry regulation, weather and other factors which
are described in further detail in the Company's filings with the Securities
and Exchange Commission.
<PAGE>
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
On July 29, 1996, the Company filed a Declaratory Judgment action in
the United States District Court for the District of Vermont. The Complaint
names as defendants a number of insurance companies that issued policies to
the Company dating from the mid 1940s to the late 1980s. The Company asserts
that policies issued by defendants provide coverage for all defense and
remediation costs associated with the Cleveland Avenue property, the
Bennington Landfill site and the North Clarendon site. With the exception of
the North Clarendon site, no further remediation is anticipated. See Note 2
to the Consolidated Financial Statements for related disclosures.
On August 7, 1997, the Company and eight other non-operating owners of
Unit #3 filed a demand for arbitration with Connecticut Light and Power
Company and Western Massachusetts Electric Company and lawsuits against NU and
its trustees. The arbitration and lawsuits seek to recover costs associated
with replacement power, operation and maintenance costs and other costs
resulting from the shutdown of Unit #3. The non-operating owners claim that
NU and two of its wholly owned subsidiaries failed to comply with NRC's
regulations, failed to operate the facility in accordance with good operating
practice and attempted to conceal their activities from the non-operating
owners and the NRC.
Except as otherwise described under Management's Discussion and
Analysis of Financial Condition and Results of Operations, Item 2, there are
no other material pending legal proceedings, other than ordinary routine
litigation incidental to the business, to which the Company or any of its
subsidiaries is a party or to which any of their property is subject.
Items 2 and 3.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
(a) The Registrant held its Annual Meeting of Stockholders on May 5,
1998.
(b) To approve the Stock Option Plan for Non-employee Directors:
For 8,868,202
Against 906,717
Abstain 253,923
(c) Director elected whose term will expire in year 2001:
Votes For Votes Withheld
Luther F. Hackett 9,727,252 301,590
Other Directors whose terms will expire in 2000:
Frederic H. Bertrand
Robert L. Barnett
Robert G. Clarke
Mary Alice McKenzie
Other Directors whose terms will expire in 1999:
Patrick J. Martin
Rhonda L. Brooks
Preston Leete Smith
Robert H. Young
Item 5. Other Information.
(a) On May 5, 1998, Joan F. Gamble was elected Assistant Vice
President of Human Resources and Strategic Planning.
Item 6. Exhibits and Reports on Form 8-K.
(a) List of Exhibits
10. Material Contracts
A 10.83 Management Incentive Plan for Executive Officers
dated January 1, 1998.
A - Compensation related plan, contract or
arrangement.
27. Financial Data Schedule.
(b) Item 5. Other Events, dated January 12, 1998 re: Connecticut
Valley Electric Company Inc. filing a motion for rehearing on
the Order dated December 31, 1997.
Other Events, dated January 28, 1998 re: The Company obtained
from its bondholders sufficient consents to implement the
Indenture amendment sought by the Company to eliminate any
cross default caused by an insolvency of or default by
Connecticut Valley Electric Company Inc.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
(Registrant)
By Francis J. Boyle
__________________________________________________
Francis J. Boyle, Senior Vice President, Principal
Financial Officer and Treasurer
By James M. Pennington
__________________________________________________
James M. Pennington, Vice President, Controller
and Principal Accounting Officer
Dated May 15, 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> 3-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> MAR-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 320,175
<OTHER-PROPERTY-AND-INVEST> 63,740
<TOTAL-CURRENT-ASSETS> 75,403
<TOTAL-DEFERRED-CHARGES> 77,981
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 537,299
<COMMON> 66,016
<CAPITAL-SURPLUS-PAID-IN> 45,302
<RETAINED-EARNINGS> 85,613
<TOTAL-COMMON-STOCKHOLDERS-EQ> 196,931
18,000
8,054
<LONG-TERM-DEBT-NET> 108,844
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 20,521
1,000
<CAPITAL-LEASE-OBLIGATIONS> 16,952
<LEASES-CURRENT> 1,094
<OTHER-ITEMS-CAPITAL-AND-LIAB> 165,903
<TOT-CAPITALIZATION-AND-LIAB> 537,299
<GROSS-OPERATING-REVENUE> 83,958
<INCOME-TAX-EXPENSE> 5,432
<OTHER-OPERATING-EXPENSES> 67,847
<TOTAL-OPERATING-EXPENSES> 73,279
<OPERATING-INCOME-LOSS> 10,679
<OTHER-INCOME-NET> 1,337
<INCOME-BEFORE-INTEREST-EXPEN> 12,016
<TOTAL-INTEREST-EXPENSE> 2,625
<NET-INCOME> 10,264
486
<EARNINGS-AVAILABLE-FOR-COMM> 9,778
<COMMON-STOCK-DIVIDENDS> 6
<TOTAL-INTEREST-ON-BONDS> 2,010
<CASH-FLOW-OPERATIONS> 16,356
<EPS-PRIMARY> .86
<EPS-DILUTED> .86
</TABLE>
EXHIBIT 10.83
- - -------------------
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
MANAGEMENT INCENTIVE PLAN
Adopted As Of January 1, 1998
I. PURPOSE
The Company's executive officers participate in the Company's Management
Incentive Plan (the "Incentive Plan"). The purpose of the Incentive Plan is
to focus the efforts of the executive team on the achievement of challenging
and demanding corporate objectives. When corporate performance attains the
specified annual performance objectives, an award is granted. A
well-directed incentive plan, in conjunction with competitive salaries,
provides a level of compensation which rewards the skills and efforts of the
executives commensurate with market comparisons.
II. ADMINISTRATION
The Incentive Plan will be administered by the Compensation Committee of the
Board of Directors (the "Committee"). All Committee actions will be subject
to review and approval by the full Board of Directors (the "Board").
At the beginning of each year ("Plan Year"), the Committee will submit to the
Board its recommendations for that Plan Year as to (i) the Incentive Plan's
Corporate Performance Goals, and (ii) the eligible participants. After the
end of each Plan Year, the Committee will report to the Board with respect to
achievement of the approved Corporate Performance Goals and individual
performance measures for that Plan Year, and will submit to the Board its
recommendations as to the appropriate award payment levels for each eligible
participant. Recommendations of the Committee, with such modifications as may
be made by the Board, will be binding on all participants in the Incentive
Plan.
III. THE PLAN
There is established a financial performance threshold, below which no
incentive awards will be paid. The threshold is determined by consolidated
earnings per share. The degree to which the consolidated earnings per share
target is achieved generates a pool which is available to fund
incentive payouts.
The pool funds awards, but performance measures must also be met in the
following areas to receive an award. Each measure is equally weighted.
Consolidated earnings per share. While this measure is used to establish the
incentive pool, it is also one of the measures which is assessed in
determining distribution of the pool.
Customer satisfaction. Measures (1) the overall degree of satisfaction by all
customers and (2) the level of satisfaction with specific service by
customers who have had a recent service interaction. The measurement is
conducted by an external firm.
Individual performance. Based on advice and recommendation from the Chief
Executive Officer for those reporting to him. The Committee evaluates the
Chief Executive Officer's performance.
If the maximum payout on all of the standards were to be achieved, the total
award would represent 35% of base salary for the Chief Executive Officer;
25% of base salary for the Chief Financial Officer, Senior Vice President
Engineering and Operations, and Vice President for and General Manager for
Business Development; 20% for other Vice Presidents, and 15% for Assistant
Vice Presidents.
IV. Any annual incentive award will consist of cash (50%) and Central
Vermont Public Service Corporation stock (50%) which will have a three year
vesting restriction. Applicable dividends will be paid on awarded restricted
stock prior to vesting.
The Board may choose to make awards of non-qualified stock options to
designated officers consistent with Plan design and intent.
V. AMENDMENTS
The Board reserves the right to amend, modify or terminate the Incentive
Plan at any time.
