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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_________
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
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)
Vermont 03-0111290
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
77 Grove Street, Rutland, Vermont 05701
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (802) 773-2711
________________________________________________________________________
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on which
Title of each class registered
Common Stock $6 Par Value New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
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 by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements or any amendment to this Form 10-K. [ ]
Cover page
State the aggregate market value of the voting stock held by non-
affiliates of the registrant: $157,923,942 based upon the closing price as of
January 31, 1996 of Common Stock, $6 Par Value, on the New York Stock Exchange
as reported in the Eastern Edition of the Wall Street Journal.
Indicate the number of shares outstanding of each of the registrant's
classes of Common Stock: As of January 31, 1996, there were outstanding
11,590,748 shares of Common Stock, $6 Par Value.
DOCUMENTS INCORPORATED BY REFERENCE
No documents are incorporated by reference in this report.
Cover page continued
Form 10-K - 1995
TABLE OF CONTENTS
Page
Part I
Item 1. Business................................................ 2
Item 2. Properties.............................................. 18
Item 3. Legal Proceedings....................................... 19
Item 4. Submission of Matters to a Vote of Security Holders..... 20
Part II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters.................................... 21
Item 6. Selected Financial Data................................. 22
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 23
Item 8. Financial Statements and Supplementary Data............. 34
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.................... 59
Part III
Item 10. Directors and Executive Officers of the Registrant...... 59
Item 11. Executive Compensation.................................. 63
Item 12. Security Ownership of Certain Beneficial Owners and
Management............................................. 69
Item 13. Certain Relationships and Related Transactions.......... 73
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K............................................ 74
Signatures........................................................ 94
PART I
Item 1. Business.
Overview.
Central Vermont Public Service Corporation (the "Company"), incorporated
under the laws of Vermont on August 20, 1929, is engaged in the purchase,
production, transmission, distribution and sale of electricity. The Company
has various wholly and partially owned subsidiaries. These subsidiaries are
described below.
The Company is the largest electric utility in Vermont and serves 135,166
customers in nearly three-quarters of the towns, villages and cities in
Vermont. This represents about 50% of the Vermont population. In addition,
the Company supplies electricity to one municipal, one rural cooperative, and
one private utility.
The Company's sales are derived from a diversified customer mix. The
Company's sales to residential, commercial and industrial customers accounted
for 56% of total MWH sales for the year 1995. Sales to the five largest retail
customers receiving electric service from the Company during the same period
constituted about 4.4% of the Company's total electric revenues for the year.
The Company's requirements resale sales accounted for approximately 4%,
entitlement sales accounted for 24% and other resale sales which include
contract sales, opportunity sales and sales to NEPOOL accounted for
approximately 16% of total MWH sales for the year 1995.
Connecticut Valley Electric Company Inc. (Connecticut Valley), a wholly
owned subsidiary of the Company, incorporated under the laws of New Hampshire
on December 9, 1948, distributes and sells electricity in parts of New
Hampshire bordering the Connecticut River. It serves 10,126 customers in 13
communities in New Hampshire. About 2% of the New Hampshire population resides
in its service area. Connecticut Valley's sales are also derived from a
diversified customer mix. Connecticut Valley's sales to residential,
commercial and industrial customers accounted for 99.5% of total MWH sales for
the year 1995. Sales to its five largest retail customers during the same
period equaled about 16% of Connecticut Valley's total electric revenues for
the year.
The Company also owns 56.8% of the common stock and 46.6% of the preferred
stock of Vermont Electric Power Company, Inc. (VELCO). VELCO owns the high
voltage transmission system in Vermont. VELCO created a wholly owned
subsidiary, Vermont Electric Transmission Company, Inc. (VETCO), to finance,
construct and operate the Vermont portion of the 450 KV DC transmission line
connecting Quebec with Vermont and New England. In addition, the Company owns
31.3% of the common stock of Vermont Yankee Nuclear Power Corporation (Vermont
Yankee), a nuclear generating company. The Company also owns 2% of the
outstanding common stock of Maine Yankee Atomic Power Company, 2% of the
outstanding common stock of Connecticut Yankee Atomic Power Company and 3.5% of
the outstanding common stock of Yankee Atomic Electric Company.
The Company has two wholly owned subsidiaries that were created for the
purpose of financing and constructing two hydroelectric facilities in Vermont:
Central Vermont Public Service Corporation - Bradford Hydroelectric, Inc.
(Bradford), which became operational December 20, 1982, and Central Vermont
Public Service Corporation - East Barnet Hydroelectric, Inc. (East Barnet),
which became operational September 1, 1984. These hydro electric facilities
have been leased and operated by the Company since their respective in-service
dates. Bradford was dissolved effective January 16, 1996.
The Company also has the following wholly owned non-utility subsidiaries:
C.V. Realty Inc., a real estate company, Catamount Energy Corporation whose
primary purpose is to invest in non-regulated, energy-supply projects, and
SmartEnergy Services, Inc. whose purpose is to profitably provide reliable
energy efficient products and services, including the rental of electric water
heaters.
Catamount Energy Corporation currently has six wholly owned subsidiaries:
(See "DIVERSIFICATION"); Catamount Rumford Corporation, Equinox Vermont
Corporation, Appomattox Vermont Corporation, Catamount Williams Lake L.P.,
Catamount Rupert Corporation and Catamount Glenns Ferry Corporation. For
additional information of the Company's diversification activities, see Item 8
herein.
REGULATION AND COMPETITION
State Commissions.
The Company is subject to the regulatory authority of the Vermont Public
Service Board (PSB) with respect to rates, and the Company and VELCO are
subject to PSB jurisdiction respecting securities issues, construction of major
generation and transmission facilities and various other matters. The Company
is subject to the regulatory authority of the New Hampshire Public Utilities
Commission as to matters pertaining to construction and transfers of utility
property in New Hampshire. Additionally, the Public Utilities Commission of
Maine and the Connecticut Department of Public Utility Control exercise limited
jurisdiction over the Company based on its joint-ownership interest as a
tenant-in-common of Wyman #4, a 619 MW generating plant and Millstone #3, an
1149 MW nuclear generating facility, respectively.
Connecticut Valley is subject to the regulatory authority of the New
Hampshire Public Utilities Commission (NHPUC) with respect to rates, securities
issues and various other matters.
Federal Power Act.
Certain phases of the businesses of the Company and VELCO, including
certain rates, are subject to the jurisdiction of the Federal Energy Regulatory
Commission (FERC) as follows: the Company as a licensee of hydroelectric
developments under Part I, and the Company and VELCO as interstate public
utilities under Parts II and III of the Federal Power Act, as amended and
supplemented by the National Energy Act.
The Company has licenses expiring at various times under Part I of the
Federal Power Act for twelve of its hydroelectric plants. The Company has
obtained an exemption from licensing for the Bradford and East Barnet projects.
Public Utility Holding Company Act of 1935.
Although the Company, by reason of its ownership of utility subsidiaries,
is a holding company, as defined in the Public Utility Holding Company Act of
1935, it is presently exempt, pursuant to Rule 2, promulgated by the Commission
under said Act, from all the provisions of said Act except Section 9(a)(2)
thereof relating to the acquisition of securities of public utility affiliates.
Environmental Matters.
In recent years, public concern for the physical environment has resulted
in increased governmental regulation of environmental matters. The Company is
subject to these regulations in the licensing and operation of the generation,
transmission, and distribution facilities in which it has interest, as well as
the licensing and operation of the facilities in which it is a co-licensee.
These environmental regulations are administered by local, state and Federal
regulatory authorities and concern the impact of the Company's generation,
transmission, distribution, transportation and waste handling facilities on
air, water, land and aesthetic qualities.
The Company cannot presently forecast the costs or other effects which
environmental regulation may ultimately have upon its existing and proposed
facilities and operations. The Company believes that any such costs related to
its utility operations would be recoverable through the rate-making process.
For additional information see Item 7 herein and refer to Item 8 herein for
disclosures relating to environmental contingencies, hazardous substance
releases and the control measures related thereto.
Nuclear Matters.
The nuclear generating facilities of Vermont Yankee and the other nuclear
facilities in which the Company has an interest are subject to extensive
regulations by the Nuclear Regulatory Commission (NRC). The NRC is empowered
to regulate the siting, construction and operation of nuclear reactors with
respect to public health, safety, environmental and antitrust matters. Under
its continuing jurisdiction, the NRC may, after appropriate proceedings,
require modification of units for which operating licenses have already been
issued, or impose new conditions on such licenses, and may require that the
operation of a unit cease or that the level of operation of a unit be
temporarily or permanently reduced. Refer to Item 8 herein for disclosures
relating to the shut down of the Yankee Atomic Nuclear Power plant.
Competition.
Competition now takes several forms. At the wholesale level, other
electric power providers compete as suppliers to resale customers. Another
competitive threat is the potential for customers to form municipally owned
utilities in the Company's service territory. At the retail level, customers
have long had energy options such as propane, natural gas or oil for heating,
cooling and water heating, and self-generation for larger customers. Changes
anticipated as a result of the National Energy Policy Act of 1992 and potential
future change in state regulatory policy may result in retail customers being
able to purchase electric power generated by competing suppliers for delivery
over the Company's transmission and distribution facilities.
Pursuant to Vermont statutes (30 V.S.A. Section 249), the PSB has
established as the service area for the Company the area it now serves. Under
30 V.S.A. Section 251(b) no other company is legally entitled to serve any
retail customers in the Company's established service area except as follows:
An amendment to 30 V.S.A. Section 212(a) enacted May 28, 1987 authorizes
the Vermont Department of Public Service (Department) to purchase and
distribute power at retail to all customers of electricity in Vermont, subject
to certain preconditions specified in new sections 212(b) and 212(c). Section
212(b) provides that a review board consisting of the Governor and certain
other designated legislative officers review and approve any retail proposal by
the Department if they are satisfied that the benefits outweigh any potential
risk to the State. However, the Department may proceed to file the retail
proposal with the PSB either upon approval by the review board or the failure
of the board to act within sixty (60) days of the submission. Section 212(c)
provides that the Department shall not enter into any retail sales arrangement
before the PSB determines and approves certain findings. Those findings are
(1) the need for the sale, (2) the rates are just and reasonable, (3) the sale
will result in economic benefit, (4) the sale will not adversely affect system
stability and reliability and (5) the sale will be in the best interest of
ratepayers.
Section 212(d) provides that upon PSB approval of the Department retail
sales proposal, Vermont utilities shall make arrangements for distributing such
electricity on terms and conditions that are negotiated. Failing such
negotiation, the PSB is directed to determine such terms as will compensate the
utility for all costs reasonably and necessarily incurred to provide such
arrangements. See Rate Developments below for additional details involving
retail sales by the Department.
In addition, Chapter 79 of Title 30 authorizes municipalities to acquire
the electric distribution facilities located within their boundaries. The
exercise of such authority is conditioned upon an affirmative three-fifths vote
of the legal voters in an election and upon the payment of just compensation
including severance damages. Just compensation is determined either by
negotiation between the municipality and the utility or, in the event the
parties fail to reach an agreement, by the Public Service Board after a
hearing. If either party is dissatisfied, the statute allows them to appeal
the Board's determination to the Vermont Supreme Court. Once the price is
determined, whether by agreement of the parties or by the PSB, a second
affirmative three-fifths vote of the legal voters is required.
There has been only one instance where Chapter 79 of Title 30 has been
invoked; the Town of Springfield acted to acquire the Company's distribution
facilities in that community pursuant to a vote in 1977. This action was
subsequently discontinued by agreement between Springfield and the Company in
1985.
In addition, in late 1994 the Select Board of the Town of Bennington
considered whether to publicly warn a vote to acquire the Company's facilities
located in Bennington pursuant to Chapter 79 of Title 30. By vote of the
Selectors taken on January 9, 1995, the Town decided not to pursue the vote at
this time.
No other municipality served by the Company, so far as is known to the
Company, has taken any formal steps in an attempt to establish a municipal
electric distribution system.
Competition in the energy services market exists between electricity and
fossil fuels. In the residential and small commercial sectors this competition
is primarily for electric space and water heating from propane and oil dealers.
Competitive issues are price, service, convenience, cleanliness and safety.
In the large commercial and industrial sectors, cogeneration and self-
generation are the major competitive threats to electric sales. Competitive
risks in these market segments are primarily related to seasonal, one-shift
operations that can tolerate periodic power outages, and for industrial
customers with steady heat loads where the generator's waste heat can be used
in their manufacturing process. Competitive advantages for electricity in
those segments are the cost of back up power sources, space requirements, noise
problems, and maintenance requirements.
In Docket DE 94-163, Order No. 21,683 (reh'g denied, Order No. 21,776),
the New Hampshire Public Utilities Commission (NHPUC) ruled that Public Service
Company of New Hampshire's (PSNH) rights to its franchise territory are not
exclusive as a matter of law. Connecticut Valley was an intervenor in that
docket. PSNH appealed the NHPUC's decision to the State of New Hampshire
Supreme Court, and Connecticut Valley has filed a brief with the Court in favor
of PSNH's position. This matter is still pending.
In Docket DR 95-250, the NHPUC seeks to implement a Retail Competition
Pilot Program (Pilot), through which three percent of each New Hampshire
electric utility's load will be available for competitive electric service from
alternative suppliers, for a period of up to two years. Connecticut Valley has
engaged in a collaborative process with interested parties, including NHPUC
Staff, and has proposed a recommendation for implementation of the Pilot in its
service territory.
For a discussion relating to utility restructuring in Vermont, see Item 7
herein.
For a discussion relating to the Company's wholesale electric business see
Wholesale Rates below.
RATE DEVELOPMENTS
Vermont Retail Rates.
In response to a March 1993 PSB inquiry into the appropriateness of a
general review of the Company's retail rates, in April 1993 the DPS and the
Company entered into a Stipulation that was approved by the PSB in September
1993. In the Stipulation the Company agreed (1) to a decrease in its allowed
rate of return on common equity from 12.5% to 12.0% for 1993, (2) to accelerate
the recovery of $1.5 million of Conservation and Load Management (C&LM) costs
deferred in 1993, (3) to not seek recovery of further C&LM costs deferred in
1993 equal to amounts in excess of the 12.0% rate of return on common equity
for 1993, and (4) to not file a general rate increase that would become
effective before August 1, 1994. The PSB in its September 1993 order also
announced the opening of an investigation on November 16, 1993, the earliest
date the Company could file for a rate increase under the Stipulation, into the
Company's cost of service and resulting rates.
In response to that investigation, on January 18, 1994 the Company filed a
revenue requirement supporting a $16.1 million or 8.0% increase in retail rates
for the year beginning November 1, 1993. The Company noted in its filing that
current rate levels are justified and that the Company does not request any
rate increase to be effective for that period. The Company also noted in its
filing that rate relief would be needed in late 1994.
On February 15, 1994, the Company filed for a rate increase of
$17.9 million or 8.9% to become effective November 1, 1994. By PSB order dated
October 31, 1994 and revised PSB order dated December 14, 1994, the PSB ordered
(1) no changes in rates pursuant to its investigation and (2) a $10.192 million
or 5.07% rate increase effective November 1, 1994 pursuant to the Company's
rate increase request. The 10.75% rate of return on common equity allowed by
the PSB was reduced by a 0.75% concurrent penalty based on the PSB's
conclusions that there had been "mismanagement of power supply options" and
because of "the Company's failed efforts to acquire all cost-effective energy
efficiency resources."
On October 17, 1995, the Company filed for a rate increase of $31.0
million or 14.6%. The PSB suspended the filing and approved a schedule for the
rate increase to become effective July 1, 1996. The rate increase is primarily
caused by increases in the cost of power and transmission, the most significant
portion of which the cost of power purchased from Hydro-Quebec. See Power
Resources below for additional discussion. The rate increase also seeks in two
ways to restore the Company's return on common equity for its Vermont utility
business. First, the Company proposes an 11.0% return on common equity.
Second, the Company seeks to remove the 0.75% concurrent ROE penalties
described above. Five individuals or entities intervened in the proceeding.
The requests of four of them, including Killington, Ltd. (Killington) were
ultimately granted by the PSB. On February 13, 1996, the Company reached an
agreement with the Department regarding this rate increase request. Under
terms of the agreement, the Company would increase rates by 5.5% effective
June 1, 1996 and by 2% effective January 1, 1997. Except for extravating
circumstances, the Company would not be able to increase rates prior to January
1, 1998 under the agreement. However, the Company believes that the rate
increase settlement reached with the Department, if approved by the PSB, will
be adequate through 1997. The agreement effectively caps the Company's allowed
return on common equity in its Vermont retail business for 1996 and 1997 at
11%, by requiring the Company to reduce deferred CL&M costs to the extent its
Vermont retail return on common equity would otherwise exceed 11%. In
addition, the agreement would remove the penalties imposed in a PSB rate order
dated October 31, 1994 discussed above. The agreement is subject to PSB
approval.
Killington, a wholly owned subsidiary of S-K-I, Ltd. (S-K-I), is a
publicly held company. Killington owns and operates the Killington Ski Area
and is one of the Company's largest customers (about 1% of retail MWH sales in
1995). Preston Leete Smith, a director of the Company since 1977, is S-K-I's
chief executive officer and chairman of its executive committee. He is also
chairman of the board of directors of Killington. Mr. Smith has informed the
Company that because he recuses himself from all matters concerning
Killington's relationship with the Company, he learned of Killington's request
to intervene after the fact and as a matter of policy continues to recuse
himself from all discussions related to the intervention, as well as other
matters related to Killington's relationship with the Company. Similarly, as a
matter of policy, Mr. Smith would recuse himself from consideration of any
matters by the Company involving Killington or S-K-I.
The Company does not believe that Killington's intervention is of itself
an action that is adverse to the Company's interests, and the Company does not
know at this time whether Killington's intervention will result in its taking
any action or legal positions adverse to the Company and if so whether such
action or legal positions would be considered material to the Company.
As required by the PSB, the Company filed in May 1995 a comprehensive
retail rate redesign which would be revenue neutral overall. The redesign
would narrow the seasonal rate differential by reducing the higher winter
charges and increasing the lower summer charges and would maintain the emphasis
on more revenue collection via fixed-type charges (KW and service charges)
instead of the more fluctuating KWH components of rates. The Company would
also offer new service options under the redesign. Negotiations between the
Company and the Department are ongoing and technical hearings before the PSB
have been scheduled for mid-1996.
The Company recognizes adequate and timely rate relief is necessary,
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.
New Hampshire Retail Rates.
Connecticut Valley's retail rate tariffs, approved by the NHPUC, contain a
fuel adjustment clause (FAC) and a purchased power cost adjustment clause
(PPCA). Under these clauses, Connecticut Valley recovers its estimated annual
costs for purchased energy and capacity which are reconciled when actual data
is available. On the basis of estimates of costs for 1995 and reconciliations
from 1994, the combined PPCA and FAC resulted in a decrease in revenues of
approximately $489,000 or 2.7% for 1995. On the basis of estimates of costs
for 1996 and reconciliations from 1995, the combined PPCA and FAC will result
in an increase in revenues of approximately $1.2 million for 1996. The NHPUC
order allowing the increase in 1996 revenues also ordered Connecticut Valley to
file testimony and supporting material concerning the Hydro-Quebec/Vermont
Joint Owners contract. The order also stated that the NHPUC would file a
letter with the FERC requesting that the FERC issue a decision on the
Wheelabrator complaint (see below) if one is pending or in the alternative
inform the NHPUC as to when to expect a decision.
Connecticut Valley's retail rate tariffs, approved by the NHPUC, also
provide for a Conservation and Load Management Percentage Adjustment (C&LMPA)
for residential and commercial/industrial customers in order to collect
forecast C&LM costs. The forecast costs are updated effective January 1 of
each year and are reconciled when actual data are available. In addition,
Connecticut Valley's earnings reflect the recovery of lost revenues related to
fixed costs which Connecticut Valley fails to otherwise recover as a result of
C&LM activities. However, the Company is not made whole because a portion of
the fixed costs of the wholesale transaction between the Company and
Connecticut Valley is not recovered when C&LM activities occur in Connecticut
Valley. The C&LMPA further provides for the future recovery of shareholder
incentives related to past C&LM activities.
In November 1995 Connecticut Valley filed its annual update of the 1996
C&LMPA rates. The Company requested approval of a decrease in program spending
and hence a decrease in revenues of $383,000 or 2.1%. Settlement negotiations
resulted in a decrease in revenues of $519,000 or 2.8% effective March 4, 1996
which the NHPUC approved.
Connecticut Valley also purchases power from several small power producers
who own qualifying facilities as defined by the Public Utility Regulatory
Policies Act of 1978. In 1995, under long-term contracts with these qualifying
facilities, Connecticut Valley purchased 40,323 MWH, of which 37,822 MWH were
purchased from a New Hampshire/Vermont solid waste plant owned by Wheelabrator
Claremont Company, L.P., (Wheelabrator). Connecticut Valley has filed a
complaint with the FERC stating its concern that Wheelabrator has not been a
qualifying facility since the plant began operation. Potential outcomes of
this complaint could result in a refund, with interest, of past purchased power
costs as well as lower future costs. Any refunds and lower future costs are
likely to be reflected in the FAC. Pursuant to a Company request, the NHPUC
issued an accounting order allowing deferral of litigation costs related to
this FERC complaint, with recovery to be determined when the outcome of the
FERC complaint is known and petitioned for implementation.
Wholesale Rates.
The Company sells firm power to Connecticut Valley under a wholesale rate
schedule based on forecast data for each calendar year which is reconciled to
actual data annually. The rate schedule provides for an automatic update of
annual rates, as well as a subsequent reconciliation to actual data. The
Company filed and the FERC approved (1) a revenue increase of $466,000 or 4.7%
for 1995 power costs, (2) a reconciliation of 1994 revenues to actual costs
which resulted in a refund of $85,482, including interest, and (3) a revenue
decrease of $78,000 or 0.7% for 1996 power costs.
As ordered by the NHPUC in Connecticut Valley's 1994 C&LMPA docket, the
Company entered into negotiations with the NHPUC Staff to redesign the RS-2
wholesale rate under which Connecticut Valley purchases power from the Company.
The redesign features marginal cost based energy and capacity charges for all
energy and capacity purchases above or below a base level. Such negotiations
concluded at the end of 1994. A summary report was filed with the NHPUC on
February 13, 1995. The NHPUC issued an order approving the summary report in
June 1995. The Company is preparing the filing with the FERC. Connecticut
Valley's costs of wholesale power will be lower than they otherwise would be
only if Connecticut Valley's growth rate exceeds that of the Company's Vermont
retail operations.
One of the Company's requirements wholesale customers, New Hampshire
Electric Cooperative, Inc. (NHEC), with an average monthly peak of 2.8 MW gave
the Company notice of termination of service under FERC Electric Tariff, First
Revised Volume No. 1, effective in March 1995. The Company negotiated a
interim temporary power sale to NHEC commencing with the termination date and a
long-term power sale effective May 1, 1995.
On March 1, 1995, the Company filed a comprehensive, open access
transmission tariff (Tariff) with the FERC. The Tariff is designed to provide
firm and non-firm network transmission service, as well as firm point-to-point
service over the transmission systems of the Company and Connecticut Valley.
In addition, the Tariff would permit customers to make use of the Company's
contract rights to the transmission facilities of the Vermont Electric Power
Company, Inc. and New England Power Company. The Tariff would provide
transmission service that is comparable to that provided to native load
customers. Charges for such service would be based upon the Company's cost of
service for transmission.
The Company prepared and filed the Tariff in anticipation of developing
business opportunities in the area of electric transmission service. In
addition, recent FERC orders led the Company to believe that all electric
utilities owning transmission facilities would be required to prepare and file
such a tariff in the near future. FERC issued a Notice Of Proposed Rulemaking
(NOPR) dated March 29, 1995, requiring such utilities to make available
comparable transmission service. The Company's tariff complies with many
requirements proposed by the FERC in its NOPR.
Nine parties intervened in the Company's Tariff filing. On April 28,
1995, the FERC issued a deficiency letter asking for more information in a
number of areas. The Company filed a timely response to the deficiency letter
on June 14, 1995. Three parties filed protests in response to the Company
filing, and one additional party filed a request for late intervention. The
FERC accepted the Tariff for filing on August 14, 1995, suspended it and set it
for hearing. The order allowed the Tariff to become effective August 15, 1995,
subject to refund and subject to the outcome of the Open Access NOPR
proceeding. The NHEC began taking transmission service under the Tariff as of
its effective date.
The Company entered into negotiations with FERC Staff and intervenors and
reached a settlement in principle in January 1996 on all rate issues contained
in the Tariff filing but one which was settled in March 1996. The settlement
provided for resolution of several rate issues based on the outcome of the NOPR
or other cases before the FERC. The non-rate issues will be decided based on
the outcome of the NOPR. However, further discussions within Vermont and New
England continue on at least some of the non-rate issues.
POWER RESOURCES
Overview.
The Company's and Connecticut Valley's energy production, which includes
generated and purchased power, required to serve their retail and firm
wholesale customers was 2,425,967 MWH for the year ended December 31, 1995.
The maximum one-hour integrated demand during that period was 407.7 MW, which
occurred on January 11, 1995. The Company's and Connecticut Valley's total
production in 1995, including production related to all resale customers, was
3,951,973 MWH.
The following tabulation shows the sources of such energy and capacity
available to the Company and Connecticut Valley for the year ended December 31,
1994 and at the time of the Company's own peak. For additional information
related to purchased power costs, refer to Item 7 herein.
Year Ended December 31, 1995
___________________________________________________
Effective Generated and
Capability Purchased at
12 Month Generated Time of the
Average and Purchased Company's Peak
__________ _________________ _______________
MW MWH % MW %
WHOLLY-OWNED PLANTS:
Hydro....................... 42.5 170,775 4.3 10.9 2.7
Diesel and Gas Turbine..... 28.5 1,925 - - -
JOINTLY OWNED PLANTS:
Millstone #3................ 19.7 138,644 3.5 7.4 1.8
Wyman #4.................... 11.0 9,992 0.2 15.6 3.8
McNeil...................... 10.5 27,191 0.7 9.9 2.4
EQUITY OWNERSHIP IN PLANTS:
(Purchased)
Vermont Yankee.............. 157.6 1,176,271 29.8 106.3 26.1
Maine Yankee................ 15.7 3,542 0.1 - -
Connecticut Yankee.......... 11.5 73,242 1.9 11.0 2.7
MAJOR LONG-TERM PURCHASES:
Hydro-Quebec................ 178.9 637,151 16.1 69.4 17.0
Merrimack #2................ 47.0 304,634 7.7 24.0 5.9
OTHER PURCHASES:
System and other purchases.. 79.9 723,088 18.3 50.9 12.5
Small Power Producers....... 34.0 190,105 4.8 16.2 4.0
Unit Purchases.............. 55.3 129,795 3.3 43.5 10.7
Entitlement Purchases....... 0.4 14,179 0.4 - -
Pumped Storage Hydro........ 4.2 4,455 0.1 3.1 0.7
NEPEX......................... - 346,984 8.8 39.5 9.7
----- --------- ----- ----- -----
TOTAL.................... 696.7 3,951,973 100.0 407.7 100.0
===== ========= ===== ===== =====
Wholly Owned Plants.
The Company owns and operates 20 hydroelectric generating facilities in
Vermont which have an aggregate nameplate capability of 41.2 MW and two gas-
fired and one diesel generating facilities on a peaking or standby basis having
a combined nameplate capability of 28.9 MW.
Jointly Owned Plants.
The Company has a joint-ownership interest in the following generating and
transmission plants:
Net
Fuel MW Generation Load Net Plant
Name Location Type Ownership Entitlement MWH Factor Investment
Millstone #3 Waterford, Nuclear 1.73% 20 138,644 79% $57,712,022
Connecticut
Wyman #4 Yarmouth, Oil 1.78% 11 9,992 10% $ 1,651,408
Maine
Joseph C. McNeil Burlington, Various 20.00% 10.6 27,191 29% $ 9,218,955
Vermont
Highgate Trans- Highgate Springs, 46.08% N/A N/A N/A $ 9,030,890
mission Facility Vermont
The Company receives its share of the output and capacity of Millstone #3,
an 1149 MW nuclear generating facility; and Wyman #4 and Joseph C. McNeil, a
619 MW and a 53 MW respectively, generating plants and is responsible for its
share of the operating expenses of each.
The Highgate Convertor, a 200 MW facility is directly connected to the
Hydro-Quebec System to the north of the Convertor and to the VELCO System for
delivery of power to Vermont Utilities. This facility can deliver power either
direction, but normally delivers power from Hydro-Quebec to Vermont.
Equity Ownership in Plants.
In 1966 the Company purchased 35% of the Vermont Yankee common stock and
was entitled to receive a like percentage of the output of the unit. In late
1969 and early 1970, the Company sold at cost a combined total of 3.7% of its
original equity investment and currently resells at cost 4.5% of its
entitlement. The Company's current equity ownership and net entitlement
percentages are 31.3 and 30.5, respectively.
The Atomic Energy Commission, now the NRC, granted a full-term (40-year),
full power operating license for the Vermont Yankee plant, which was to expire
in December 2007. On December 17, 1990 the NRC issued an amendment of the
operating license extending its term to March 2012.
Vermont Yankee's net capability is 514 MW of which 156.7 MW (See Note 1)
is the Company's net entitlement. Vermont Yankee's plant performance for the
past five years is shown below:
Availability Capacity
Factor Factor
(See Note 2) (See Note 3)
1991......................... 93.6 91.2
1992......................... 87.5 82.7
1993......................... 78.3 74.9
1994......................... 98.2 95.8
1995......................... 86.3 84.8
Vermont Yankee was down for scheduled refueling outages in 1993 and 1995,
as well as unscheduled outages in 1993.
As described in the overview section above, the Company is a stockholder,
together with other New England electric utilities, in the following three
nuclear generating companies: Maine Yankee Atomic Power Company, Connecticut
Yankee Atomic Power Company and Yankee Atomic Electric Company.
Net Company's
Company Capability Entitlement
Maine Yankee (See Note 4)..... 847 MW 2.0% - 16.9 MW
Connecticut Yankee............ 582 MW 2.0% - 11.6 MW
Yankee Atomic................. (See Note 5) (See Note 5)
The Company is obligated to pay its entitlement percentage of the
operating expenses of Vermont Yankee and the other Yankee companies, including
depreciation and a return on invested capital, whether or not the plant is
operating. The Company is obligated to contribute its entitlement percentage
of the capital requirements of Vermont Yankee and Maine Yankee and has a
similar, but more limited obligation to Connecticut Yankee. The Company's
entitlement percentages are identical to the ownership percentages except that
Vermont Yankee's entitlement percentage is 35%. For additional information
regarding Equity Ownership in Plants, refer to Item 8 herein.
_______________
Notes:
(1) Currently, the Company resells at cost, through VELCO, 23.2 MW of its
original entitlement to other Vermont utilities.
(2) "Availability Factor" means the hours that the plant is capable of
producing electricity divided by the total hours in the period.
(3) "Capacity Factor" means the total net electrical generation divided by
the product of the maximum design electrical rating capacity of 514
through April 30, 1995 and 522 effective May 1, 1995, multiplied by
the total hours in the period.
(4) Currently, the Company resells at cost 1.8 MW of its entitlement to
certain municipal utilities in Massachusetts.
(5) Yankee Atomic permanently ceased power operations of the Yankee Nuclear
Power Station. See Decommissioning Expense discussion below.
Decommissioning Expense.
Each of the Yankee companies and Millstone #3 has developed its own
estimate of the cost of decommissioning its nuclear generating unit. These
estimates vary depending upon the method of decommissioning, economic
assumptions, site and unit specific variables, and other factors. Each of the
Yankee Companies includes charges for decommissioning costs in the cost of
capacity, as approved by the FERC. Decommissioning costs for Millstone #3 are
included in depreciation expenses.
The Company's entitlement percentage of decommissioning costs for Vermont
Yankee, Connecticut Yankee, Maine Yankee, Yankee Atomic and Millstone #3 is as
follows (dollars in millions):
CVPS's
Total Share of
Date of Estimated CVPS's Funded
Study Obligation Obligation Obligation
Nuclear generating companies:
Vermont Yankee 1993 $312.7 $109.4 $47.1
Maine Yankee 1993 $316.6 $6.3 $2.8
Connecticut Yankee 1992 $309.0 $6.2 $3.6
Yankee Atomic 1994 $370.0 $13.0 $3.9
Millstone #3 1992 $477.9 $8.3 $1.4
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. See Item 8 for additional disclosure.
The Company owns interests in two of the five nuclear plants operated by
Northeast Utilities (NU): 1) a 2% equity interest in the Connecticut Yankee
Atomic Power Company (Haddam Neck Plant), and 2) a 1.7303% joint-ownership
interest in the Millstone Unit #3 of the Millstone Nuclear Power Station.
In March 1996, the NRC ordered NU to submit a plan within 30 days
verifying operational compliance with licensing documentation at Millstone Unit
#3 and the Haddam Neck Plant, or risk having the plants shut down. This order
follows noncompliances discovered at two of Northeast Utilities' other nuclear
units. The Company is unable to determine at this time what the results of the
NRC order will be on the operations of the Millstone Unit #3 and Haddam Neck
Plant, or what the impact would be on the Company if the units were to be shut
down.
For information regarding the premature shutdown of Yankee Atomic nuclear
power plant, refer to Item 8 herein.
In 1982 the State of Maine enacted legislation that requires the
development of a decommissioning trust fund for the Maine Yankee nuclear plant.
This statute also provides that, if the trust has insufficient funds to
decommission the plant, the licensee, Maine Yankee, is responsible for the
deficiency and, if the licensee is unable to provide the entire amount, the
owners of the licensee are jointly and severally responsible for the remainder.
The definition of owner under the statute includes the Company. It is expected
that any payments required by the Company under these provisions would be
recovered through rates.
Nuclear Fuel.
Vermont Yankee has approximately $123.8 million of "requirements based"
purchase contracts for nuclear fuel needs to meet substantially all of its
power production requirements through 2002. Under these contracts, any
disruption of operating activity would allow Vermont Yankee to cancel or
postpone deliveries until actually needed.
Vermont Yankee has a contract with the United States Department of Energy
(DOE) for the permanent disposal of spent nuclear fuel. Under the terms of
this contract, in exchange for the one-time fee discussed below and a quarterly
fee of $.001 per KWH of electricity generated and sold, the DOE agrees to
provide disposal services when a facility for spent nuclear fuel and other
high-level radioactive waste is available, which is required by contract to be
prior to January 31, 1998.
The DOE contract obligates Vermont Yankee to pay a one-time fee of
$39.3 million for disposal costs for all spent fuel discharged through April 7,
1983. Although such amount has been collected in rates from the Sponsors,
Vermont Yankee has elected to defer payment of the fee to the DOE as permitted
by the DOE contract. The fee must be paid no later than the first delivery of
spent nuclear fuel to the DOE. Interest accrues on the unpaid obligation based
on the thirteen-week Treasury Bill rate and is compounded quarterly. Through
1995 Vermont Yankee accumulated approximately $65.9 million in an irrevocable
trust to be used exclusively for defeasing this obligation ($89.0 million
including accrued interest) at some future date provided the DOE complies with
the terms of the aforementioned contract.
The average energy and capacity costs to the Company of energy generated
at the Vermont Yankee plant was 3.69, 4.71, 5.34, 3.77 and 4.68 cents per KWH
for the years 1991 through 1995, respectively.
The Company has been advised by the companies operating other nuclear
generating stations in which the Company has an interest that they have
contracted for certain segments of the nuclear fuel production cycle through
various dates. Contracts for the remainder of the fuel cycle will be required
but their availability, prices and terms cannot be predicted.
Nuclear Liability and Insurance.
The Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $8.9 billion. Any damages beyond $8.9
billion are indemnified under an agreement with the Nuclear Regulatory
Commission, but subject to Congressional approval. The first $200 million of
liability coverage is the maximum provided by private insurance. The Secondary
Financial Protection Program is a retrospective insurance plan providing
additional coverage up to $8.7 billion per incident by assessing each of the
110 reactor units that are currently subject to the Program in the United
States, a total of $79.3 million, limited to a maximum assessment of
$10 million per incident per nuclear unit in any one year. The maximum
assessment is expected to be adjusted at least every five years to reflect
inflationary changes. The Company's interests in the nuclear power units are
such that it could become liable for an aggregate of approximately $4.1 million
of such maximum assessment per incident per year.
Major long-term purchases.
Canadian Purchases - Under various contracts, the Company purchases from
Hydro-Quebec capacity and associated energy. Under the terms of these
contracts, the Company is required to pay certain fixed capacity costs whether
or not energy purchases above a minimum level described in the contracts are
made. Such minimum energy purchases must be made whether or not other less
expensive energy sources might be available.
The Company will receive varying amounts of capacity and energy from
Hydro-Quebec under the Vermont Joint Owners (VJO) contract during the 1996-2016
period. A contract between the state of Vermont and Hydro-Quebec terminated on
September 22, 1995. Related contracts were negotiated between the Company and
Hydro-Quebec which in effect alter the terms and conditions contained in the
VJO contract, reducing the overall power requirements and cost of the original
contract.
The maximum net amount of capacity that the Company will purchase during
the term of the agreements is 143 MW. The total commitment in the next five
years to purchase power under these contracts is approximately $346 million,
less approximately $98 million of power sellbacks, yielding a net cost of
approximately $248 million. The Company recently reached an agreement with
Hydro-Quebec that will lower our 1997 cost of power by approximately
$5.8 million. As part of this agreement, the Company will deliver to NEPOOL
under existing firm energy contracts or joint marketing activities 54 MW of
Phase II transmission capacity (see Transmission, Phase I and Phase II below)
for a five-year period beginning July 1, 1996 through June 30, 2001. In
addition, the agreement provides for continuing negotiations with Hydro-Quebec
to further reduce future power cost increases.
In the early phase of the VJO contract, two sellback contracts were
negotiated, the first delaying the purchase of about 24 MW of capacity and
associated energy, the second reducing the net purchase of Hydro Quebec power.
In 1994, the Company negotiated a third sellback arrangement whereby the
Company receives an effective discount on up to 70 MW of capacity starting in
November 1995 for the 1996 contract year (declining to 30 MW in the 1999
contract year). In exchange for this sellback, Hydro-Quebec has the right to
reduce capacity deliveries by up to 50 MW beginning as early as 2004 until
2015, including the use of a like amount of the Company's Phase I/II facility
rights and the ability to reduce the amounts of energy delivered during a
five-year term beginning in 2000.
Details of these purchases and sell-back contracts are described in the
table that follows (dollars in thousands):
State of VT Schedule Schedule Schedule Schedule Schedule Schedule
Contract A C-1 C-2 B C-3 C-4a
Capacity in MW 69 25 31 21 93 - 24
Contract period '85-'95 '91-'95 '91-'12 '92-'12 '95-'15 '95-'15 '96-'12
Minimum energy(load factor) 50.0% 50.0% 75.0% 75.0% 75.0% 75.0% 75.0%
Minimum annual MWH 220,752 79,844 201,863 138,141 610,077 26 155,801
Actual 1995 energy charges $4,209 $2,570 $4,885 $3,343 $3,373 $0 N/A
Estimated 1st full year future
energy charges N/A N/A $5,040 $3,449 $15,204 $1,000 $4,140
Estimated average % change from
1st year future 3.0% 3.0% 3.0% 3.0% 3.0%
('96-'12) ('96-'12) ('96-'15) ('96-'15) ('96-'12)
Actual 1995 annual capacity charge $3,224 $1,740 $7,252 $5,016 $6,467 $0 N/A
Estimated 1st year future
capacity charge N/A N/A $7,374 $5,046 $23,431 $1 $6,071
Estimated average % change from 1st
year future 0.0% 0.0% 0.0% 0.0% 0.0%
('96-'12) ('96-'12) ('96-'15) ('96-'15) ('96-'12)
Actual 1995 average cost in cents/KWH 3.0 5.5 6.0 6.1 7.1 N/A N/A
Estimated 1st year future
average cost in cents/KWH N/A N/A 6.1 6.1 6.3 6.3 6.6
Estimated average % change from 1st
year future 1.2% 1.2% 1.2% 1.2% 1.2%
('96-'12) ('96-'12) ('96-'15) ('96-'15) ('96-'12)
1995 Sellback in average MW N/A 25 30 20 2.6 N/A N/A
Actual 1995 sellback revenue $0 $4,310 $9,526 $6,553 N/A N/A N/A
Expected sellback #1 revenue 25 MW
Estimated 1st year future annual $10,101
(1996)
Estimated out-years average annual $11,060
Estimated average annual % change 1.2%
('97-'12)
Expected sellback #2 revenue 5.7 MW 20 MW
Estimated 1996 annual $1,433 $5,006
Expected sellback #3-net sellback & purchase up to 70 MW
Approx. 90% of capacity costs
Est.1st contract yr. (11/95-10/96) future $16,170 70 MW
Est.2nd contract yr. (11/96-10/97) future $11,400 50 MW
Est.3rd contract yr. (11/96-10/98) future $9,120 40 MW
Est.4th contract yr. (11/98-10/99) future $6,840 30 MW
Merrimack #2 - The Company, through Velco, purchases power from Merrimack #2, a
320 MW capacity coal-fired steam unit located in Bow, New Hampshire, and owned
by NU under a thirty-year contract which expires April 30, 1998.
Beginning in 1995, the Merrimack #2 unit is subject to air emission limits
for sulfur dioxide (SO2) and Nitrogen Oxides (NOx) mandated by the Clean Air
Act Amendments of 1990 (CAAA). The CAAA establishes SO2 allowances to reduce
SO2 emissions. NU expects to have sufficient SO2 allowances to meet CAAA SO2
requirements. If any gains are realized from the sale of excess allowances,
the Company will receive its proportionate share from VELCO. Likewise, the
Company will pay its share of any allowances purchased.
NU complied with the Merrimack #2 NOx limits by installing Selective
Catalytic Reduction (SCR) equipment in 1995 at a cost of approximately
$19 million increasing operating costs by about $1.6 million annually. The SCR
equipment is expected to have a negligible effect on unit fuel efficiency. The
Company will share on a pro-rata basis the cost of the SCR equipment based on
its share of the VELCO contract. The total cost to the Company of energy
generated by the Merrimack #2 unit was 3.03 cents per KWH in 1995.
Beginning in 1995, under the Clean Air Act Amendment of 1990, the plant is
required to purchase allowances if its output of sulfur dioxide (SO2) exceeds
about 21,400 tons of which the Company's share is about 3,100 tons. In 1995,
Merrimack 2 emitted about 26,000 tons and the Company's share was about 3,800
tons, which required the purchase of allowances for a cost of approximately
$600,000. The Company's share was about $87,000.
Other Purchases.
Cogeneration/Small Power Qualifying Facilities - A number of small
producers using hydroelectric, biomass, and refuse-burning generation are
currently producing energy that the Company is purchasing. For the year ended
December 31, 1995, the Company received 190,105 MWH from these sources for
which it paid $19,169,894.
New England Power Pool - The Company, through VELCO, is a participant in
the New England Power Pool (NEPOOL), which is open to all investor-owned,
municipal and cooperative utilities in New England under an agreement in effect
since 1971. The NEPOOL Agreement provides for joint planning and operation of
generating and transmission facilities and also incorporates generating
capacity reserve obligations and provisions regarding the use of major
transmission lines and payment for such use. Because of its participation in
NEPOOL, the Company's operating revenues and costs are affected to some extent
by the operations of other participants in that agreement.
The primary purposes of NEPOOL are to provide energy reliability for the
region, centralized economic dispatch and coordination of generation planning
and construction by the individual participants. The Company's peak demand for
1995 occurred on January 11, 1995 and equaled 407.7 MW. At the time of this
peak, the Company had a reserve margin of 31.0%. NEPOOL's peak for the year
occurred on July 27, 1995 and totaled 20,499 MW. NEPOOL had a 26% reserve
margin at the time of its 1995 peak.
Power Resources - Future.
The Company purchases about 90% of the power it needs, including the power
it receives as part owner of the various Yankee nuclear plants. In 1995, about
30% of the Company's purchased power came from renewable sources, primarily
water and wood. The Company's core business has no plans at this time to build
any new generating facilities to supply power, instead it intends to satisfy
customers' energy needs through a combination of power purchases and
energy-efficiency services. Therefore, the Company uses a process called
"integrated
resource planning," or IRP, to help determine the resources necessary to meet
future power needs. IRP is an evolving, on-going process. An
interdisciplinary team representing various functional planning area works
together continuously to coordinate and integrate planning. The primary
objective of IRP is to provide reliable, least-cost energy resources consistent
with the Company's policy to protect the environment. The choice of least-cost
resources explicitly seeks a balance between traditional supply resources and
energy efficiency investments with the Company's customers. Flexibility and
diversity are investment guidelines designed to provide least-cost resources
over a broad range of possible futures.
Based upon current load forecasts, the Company expects to be able to
satisfy its load requirements into the first decade of the next century through
its ownership in various generating facilities and purchases from various other
New England, New York, Canadian utilities, Independent Power Producers, and
Conservation and Load Management. Current load and capacity forecasts for
NEPOOL indicate adequate reserves and availability of power for the region as a
whole and the Northeast well past the year 2000.
TRANSMISSION
Vermont Electric Power Company, Inc.
VELCO engages in the operation of a high-voltage transmission system which
interconnects the electric utilities in the State including the areas served by
the Company. VELCO is also engaged in the business of purchasing bulk power
for resale, at cost, to the Company and the other electric utilities
(cooperative, municipal and investor-owned) in Vermont (the "Vermont
utilities") and transmitting such power for the Vermont utilities. Refer to
Item 8 herein for a discussion of the 1985 Four Party Agreement between the
Company, VELCO and two other major distribution companies in Vermont.
VELCO provides transmission services for the State of Vermont, acting by
and through the Department, and for all of the electric distribution utilities
in the State of Vermont. VELCO is reimbursed for its costs (as defined in the
agreements relating thereto) for the transmission of power for such entities.
The Company, as the largest electric distribution utility in Vermont, is the
major user of VELCO's transmission system.
The Company owns 34,083 shares (56.8%) of the Class B common stock of
VELCO, the balance being owned by other Vermont utilities. Each share of Class
B common stock has one vote. The Company also owns 46,624 shares (46.6%) of
the Class C preferred stock of VELCO, the balance being owned by other Vermont
utilities. Shares of Class C preferred stock have no voting rights except the
limited right to vote VELCO's shares of common stock in Vermont Electric
Transmission Company, Inc. (VETCO) if certain dividend requirements are not
met.
NEPOOL Arrangements.
VELCO participates for itself and as agent for the Company and twenty-one
other Vermont utilities in NEPOOL. See "Business-New England Power Pool" for
additional details.
Capitalization.
VELCO has authorized 92,000 shares of Class B common stock, $100 par
value, of which 60,000 shares were outstanding on December 31, 1995 and 125,000
shares of Class C preferred stock, of which 100,000 shares were outstanding at
December 31, 1995. On that date there were authorized and outstanding three
issues of First Mortgage Bonds, aggregating $34,558,000, issued under an
Indenture of Mortgage dated as of September 1, 1957, as amended, between VELCO
and Bankers Trust Company, as Trustee (the "VELCO Indenture"). The issuance of
bonds under the VELCO Indenture is unlimited in amount but is subject to
certain restrictions.
New transmission and associated facilities will be required by VELCO in
1996 to transmit power to Vermont utilities. The costs of such facilities are
presently estimated at $7,600,000 including allowance for funds used during
construction calculated at a rate of approximately 6.75%. For a description of
VELCO's properties, see "VELCO" under Item 2.
Management.
In 1957 VELCO entered into an agreement (the "Three-Party Agreement")
whereby the Company and Green Mountain agreed that, if VELCO transmits firm
power owned by it (which it does not now do), they would have the right to
purchase all such firm power not sold to others with their consent and the
obligation to pay (in agreed proportions) amounts sufficient, together with
VELCO's revenues from other sources, to pay all VELCO's operating expenses,
debt service and taxes. In connection with the transfer to VELCO of
entitlements of the output of the Vermont Yankee plant, the Company and Green
Mountain entered into a Three-Party Transmission Agreement, dated November 21,
1969, as amended, whereby they have agreed to pay transmission charges thereon
in an aggregate amount sufficient, with VELCO's other revenues, to pay all of
VELCO's expenses including capital costs. VELCO's Bonds are secured by a first
mortgage on the major part of VELCO's transmission properties and by the
assignment to the Trustee of the Three-Party Agreement, the Three-Party
Transmission Agreement and certain other contracts as specified in the VELCO
Indenture. See Item 8 herein for information relating to the 1985 Four-Party
Agreement.
Vermont Electric Transmission Company, Inc.
In connection with the importing of Canadian power, VELCO has created a
wholly owned subsidiary, VETCO, to construct, finance, own and operate the
Vermont portion of the transmission line which connects the Hydro-Quebec lines
at the Canadian border to the lines of New England Electric Transmission
Corporation, a subsidiary of New England Electric System, at the New Hampshire
border on the Connecticut River. VETCO entered into a Capital Funds Agreement
with VELCO pursuant to which VETCO may request up to $12,500,000 (of which
$10,000,000 was contributed as of December 31, 1995) of capital contributions
from VELCO and has entered into Transmission Line Support Agreements with 20
New England utilities, including VELCO as representative for 15 Vermont
utilities, pursuant to which those utilities have agreed to pay the
transmission line costs, whether or not the line is operational. VELCO, as
such representative, has entered into a similar agreement with New England
Electric Transmission Corporation with respect to the New Hampshire portion of
the DC transmission line and the DC/AC converter station. VELCO has entered
into a Vermont Participation Agreement and a Capital Funds Support Agreement
with 15 Vermont distribution utilities, including the Company, pursuant to
which those utilities assume their pro rata share (based upon 1980 sales) of
the benefits and obligations of VELCO under the Support Agreements and the
VETCO Capital Funds Agreement.
VETCO has authorized 10 shares of common stock, $100 par value, all of
which were outstanding on December 31, 1995 and owned by VELCO, with each share
having one vote. During 1986 VETCO paid off its construction financing by
issuing $37,000,000 of secured notes, maturing in 2006, and receiving a
$9,999,000 equity contribution from VELCO. The notes are secured by a First
Mortgage on the major part of VETCO's transmission properties and by the
assignment of its rights under the Support Agreements.
Phase I and Phase II.
The Company participated with other electric utilities in the construction
of the Phase I Hydro-Quebec transmission facilities in northeastern Vermont,
which were completed at a total cost of approximately $140 million. Under a
support agreement relating to the Company's participation in the facilities,
the Company is obligated to pay its 4.42% share of Phase I Hydro-Quebec capital
costs over a 20 year recovery period through and including 2006. The Company
also participated in the construction of Phase II Hydro-Quebec transmission
facilities which began operation in November 1990. This service increased the
maximum capacity of the Hydro-Quebec 450 KV DC line from 690 MW to 2000 MW and
extended Phase I line from Comerford, New Hampshire to Sandy Pond,
Massachusetts. The Company uses this transmission path to deliver a portion of
the Company's long-term Hydro-Quebec firm power contract. The project cost
approximately $487 million. Under a similar support agreement, the Company is
obligated to pay its 5.132% share of Phase II Hydro-Quebec capital costs over a
25-year recovery period through and including 2015. Under the support
agreement, the Company is eligible for savings associated with certain energy
transactions by NEPOOL, which will offset the Company's support cost
obligations.
CONSERVATION AND LOAD MANAGEMENT
The primary purpose of Conservation and Load 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. For additional
information regarding C&LM programs see Item 7, "Liquidity and Capital
Resources" herein.
The Company provides information to customers to help them use electricity
more efficiently, first by ensuring that the customers are on the correct rate
and have incorporated efficiency and conservation measures; secondly, by
continually evaluating new energy management systems and other technologies to
identify and develop programs to address new market opportunities and the
competitive strengths of electricity.
DIVERSIFICATION
See Items 7 and 8 herein for information regarding the Company's
diversification activities.
The Company is continually assessing additional diversification
opportunities. Any new investments will be financed primarily through a
combination of debt and equity.
EMPLOYEE INFORMATION
A Local Union No. 300 affiliated with the International Brotherhood of
Electrical Workers represents operating and maintenance employees of the
Company and its wholly owned subsidiaries. At December 31, 1995 the Company
and its wholly owned subsidiaries employed 670 persons, of which 234 are
represented by the union. On December 31, 1992, the Company and its employees
represented by the union agreed to a three-year contract, which provided for an
annual wage increase of 3.95% for a three year period ending December 31, 1995.
This contract expired on December 31, 1995, but it was extended until January
26, 1996, when a new three-year contract was agreed to by the Company and its
employees represented by the Union. The new contract expires on December 31,
1998 and provides for general wage increases of 2.0%, 2.1% and 2.5% effective
January 14, 1996, December 29, 1996 and December 28, 1997, respectively. Under
the terms of the new agreement, effective in April 1996, Company's employees
represented by the union will contribute weekly premiums for medical coverage
of two, three and four dollars for the years 1996, 1997 and 1998, respectively.
SEASONAL NATURE OF BUSINESS
The Company experiences its heaviest loads in the colder months of the
year. Winter recreational activities, longer hours of darkness and heating
loads from cold weather usually cause the Company's peak of electric MWH sales
to occur in January or late December. For additional information regarding the
seasonal nature of business see Item 8 herein.
Item 2. Properties.
The Company. The Company's properties are operated as a single system
which is interconnected by transmission lines of VELCO, New England Power
Company and PSNH. The Company owns and operates 21 small generating stations
with a total current nameplate capability of 66,370 KW, has a 1.78%
joint-ownership interest in an oil generating plant in Maine, has a 20%
joint-ownership interest in a wood, gas and oil-fired generating plant in
Vermont,
has a 1.73% joint-ownership interest in a nuclear generating plant in
Connecticut, has a 46.08% joint-ownership interest in a transmission
interconnection with Hydro-Quebec in Vermont and leases and operates two hydro
generating stations from wholly owned subsidiaries, Bradford and East Barnet,
1,500 KW and 2,200 KW, respectively. However, Bradford was dissolved effective
January 16, 1996.
The electric transmission and distribution systems of the Company include
about 614 miles of overhead transmission lines, about 7,228 miles of overhead
distribution lines and about 223 miles of underground distribution lines which
are located in Vermont except for about 23 miles of transmission lines which
are located in New Hampshire and about two miles of transmission lines which
are located in New York.
Connecticut Valley. Connecticut Valley's electric properties consist of
two principal systems in New Hampshire which are not interconnected with each
other but each of which is connected directly with facilities of the Company.
The electric systems of Connecticut Valley include about two miles of
transmission lines and about 426 miles of overhead distribution lines and about
11 miles of underground distribution lines.
All the principal plants and important units of the Company and its
subsidiaries are held in fee. Transmission and distribution facilities which
are not located in or over public highways are, with minor exceptions, located
either on land owned in fee or pursuant to easements substantially all of which
are perpetual. Transmission and distribution lines located in or over public
highways are so located pursuant to authority conferred on public utilities by
statute, subject to regulation of state or municipal authorities.
VELCO. VELCO's properties consist of about 483 miles of high voltage
overhead transmission lines and associated substations. The lines connect on
the west at the Vermont-New York state line with the lines of Niagara Mohawk
Power Corporation near Whitehall, New York, and Bennington, Vermont and with
the submarine cable of NYPA near Plattsburg, New York; on the south and east
with lines of New England Power Company and PSNH; on the south with the
facilities of Vermont Yankee; and on the north with lines of Hydro-Quebec
through a converter station and tie line jointly owned by the Company and
several other Vermont utilities.
VETCO. VETCO has approximately 52 miles of high voltage DC transmission
line connecting at the Quebec-Vermont border in the Town of Norton, Vermont
with the transmission line of Hydro-Quebec and connecting at the Vermont-New
Hampshire border near New England Power Company's Moore hydro-electric
generating station with the transmission line of New England Electric
Transmission Corporation, a subsidiary of New England Electric System.
Item 3. Legal Proceedings.
On March 20, 1992, Sunnyside Cogeneration Associates filed suit in the
United States District Court for the District of Vermont against the Company,
CV Energy Resources, Inc. (CVER) and a subsidiary of CVER alleging damages in
excess of five million dollars resulting from the parties' inability to come to
agreement on the terms of CVER's proposed investment in the plaintiff's waste
coal cogeneration facility under construction in Sunnyside, Utah. The Company
filed an answer denying the allegations and both sides have filed motions for
summary judgment which were denied. The plaintiff has also submitted its
Requests for Finding of Fact, in which it claims damages of approximately
$8.7 million. The case is expected to be tried later this spring or summer.
On December 30, 1994, a lawsuit was filed in the United States District
Court for the District of Vermont, Civil Action No. 2:94-CV386, by Bradford E.
White, Michel J. Messier and John A. Wasik, against the Company, its present
directors and certain former directors. This lawsuit (the "Shareholder Suit"),
which purports to be on behalf of a class of consumers as well as on behalf of
the Company s stockholders in enforcing the rights of the Company, alleges,
among other things, (i) that F. Ray Keyser, Jr., Chairman of the Company's
Board of Directors, violated Section 8 of the Clayton Act, 15 U.S.C. Subchapter
19, which precludes certain interlocking directorships, (ii) that Mr. Keyser
violated his fiduciary duties to the Company's stockholders by acquiring and
operating a series of businesses in competition with the Company without
offering those business opportunities to the Company, (iii) that the remaining
individual defendants violated their fiduciary duties to the Company's
stockholders by failing to analyze, or to cause management to analyze,
diversification into propane and fossil fuels, and by failing to make the
Company an effective competitor of alternative fuel companies, and (iv) that
the Company violated the applicable provision of the Vermont General
Corporation Law by failing to provide a list of the Company's stockholders.
The Shareholder Suit seeks an unspecified amount of damages (including treble
damages against Mr. Keyser), attorney's fees and costs, a list of the Company's
stockholders, and a court order to enjoin the defendants from alleged
continuing violations of the law. Each of the individual defendants and the
Company itself deny the allegations against them and intend to vigorously
defend the Shareholder Suit. The Company and its directors have filed a Motion
to Dismiss which is currently pending before the Court. Information regarding
the Company's advancement of expenses incurred by the Company's directors in
connection with the Shareholder Suit is set forth in Item 13 below under the
captions "Report of Indemnification and Advancement of Expenses" and
"Compensation Committee Interlocks and Insider Participation".
In response to a shareholder letter received in November 1994, the
Company's Board formed a Special Investigation Committee (the Committee),
comprised of three outside directors, to investigate the shareholder's
allegations concerning management's judgment in deciding, in August 1991, to
commit, as part of a consortium of Vermont utilities, to a long-term purchase
of a large amount of hydro-electric power from Hydro-Quebec. The shareholder
also alleged that the Company misled the PSB, prior to the Company's decision
to commit to the purchase, concerning the status of negotiations relating to
the purchase. The Committee hired outside counsel to aid in the investigation
and to render legal advice to it and the Board. At the conclusion of its
investigation, the Committee recommended to the outside members of the full
Board that pursuit of any legal claims implicated by the shareholder's letter
would not be in the best interests of the Company and its shareholders and that
the Company should take no further action with respect to the shareholder's
letter. At the Board's regularly scheduled meeting in September 1995, the
outside directors of the Board voted unanimously to adopt the Committee's
recommendations.
At the Company's 1994 Annual Meeting, shareholders approved two amendments
to the Company's Articles of Incorporation subject to obtaining the necessary
regulatory approval. One of the amendments was a so-called Fair Price
provision. The other amendment served to limit The Board of Directors'
liability in certain circumstances. Because, under Vermont law, the Company
cannot amend its Articles of Incorporation without the Public Service Board's
(PSB) permission, the Company filed a petition seeking the necessary regulatory
approval. The Department of Public Service vigorously opposed both amendments,
significantly decreasing the likelihood of obtaining PSB approval. The case
was further complicated by the participation of Mr. Bradford White, a plaintiff
in the lawsuit discussed in the afore mentioned paragraph. In light of the
limited prospect of obtaining regulatory approval, as well as the ongoing costs
associated with the proceeding, the Company decided to withdraw the petition
with prejudice. Accordingly, on October 17, 1995, the Company filed a notice
of withdrawal, which the PSB granted.
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.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to security holders during the fourth
quarter of 1995.
PART II
Item 5. Market for Registrant's Common Equity
and Related Stockholder Matters.
(a) The Company's common stock is traded on the New York Stock Exchange
(NYSE) under the trading symbol CV.
The table below shows the high and low sales price of the Company's common
stock, as reported on the NYSE composite tape by The Wall Street Journal, for
each quarterly period during the last two years as follows:
Market Price
High Low
1995
First quarter.............. $ 14 1/4 $ 13 1/4
Second quarter............. 14 1/4 13 1/4
Third quarter.............. 14 3/8 13 3/8
Fourth quarter............. 14 3/8 13 1/4
1994
First quarter.............. $ 22 $ 18 3/8
Second quarter............. 19 1/8 14 1/4
Third quarter.............. 15 1/2 12 1/8
Fourth quarter............. 14 1/2 12 3/8
(b) As of December 31, 1995, there were 15,718 holders of the Company's
common stock, $6 par value.
(c) Common stock dividends have been declared quarterly. Cash dividends
of $.355 per share were paid for all quarters of 1994 and cash dividends of
$.20 were paid for all quarters of 1995.
So long as any Senior Preferred Stock or Second Preferred Stock is
outstanding, except as otherwise authorized by vote of two-thirds of each such
class, if the Common Stock Equity (as defined) is, or by the declaration of any
dividend will be, less than 20% of Total Capitalization (as defined), dividends
on Common Stock (including all distributions thereon and acquisitions thereof),
other than dividends payable in Common Stock, during the year ending on the
date of such dividend declaration, shall be limited to 50% of the Net Income
Available for Dividends on Common Stock (as defined) for that year; and if the
Common Stock Equity is, or by the declaration of any dividend will be, from 20%
to 25% of Total Capitalization, such dividends on Common Stock during the year
ending on the date of such dividend declaration shall be limited to 75% of the
Net Income Available for Dividends on Common Stock for that year. The defined
terms identified above are used herein in the sense as defined in subdivision
8A of the Company's Articles of Association; such definitions are based upon
the unconsolidated financial statements of the Company. As of December 31,
1995, the Common Stock Equity of the Company was 56.4% of total capitalization.
For additional information regarding dividend payment level and dividend
restrictions see Item 8 herein.
Item 6. Selected Financial Data.
(Dollars in thousands, except per share amounts)
1995 1994 1993 1992 1991
For the year
Operating revenues $288,277 $277,158 $279,389 $275,375 $233,469
Net income* $ 19,851 $ 14,800 $ 21,292 $ 21,422 $ 18,576
Earnings available for common stock* $ 17,823 $ 12,662 $ 18,634 $ 18,764 $ 17,514
Consolidated return on average
common stock equity* 10.0% 7.2% 11.0% 11.8% 11.8%
Earnings per share of common stock* $1.53 $1.08 $1.64 $1.71 $1.65
Cash dividends paid per share of
common stock $.80 $1.42 $1.42 $1.39 $1.39
Book value per share of common stock $15.51 $14.56 $15.03 $14.21 $14.03
Net cash provided by operating
activities $ 41,711 $ 49,410 $ 36,833 $ 48,904 $ 42,033
Dividends paid $ 11,350 $ 18,845 $ 18,112 $ 18,174 $ 15,677
Construction and plant expenditures $ 21,337 $ 22,621 $ 20,519 $ 20,503 $ 18,950
Deferred conservation and load
management expenditures $ 3,899 $ 6,159 $ 9,874 $ 3,539 $ 1,946
At end of year
Long-term debt $120,142 $120,157 $122,419 $107,879 $130,163
Redeemable preferred stock $ 20,000 $ 20,000 $ 20,000 $ 20,000 $ 20,000
Total capitalization
(excluding current portion of debt) $327,956 $318,995 $331,309 $302,023 $316,897
Total assets $490,062 $490,399 $480,150 $451,052 $430,748
* After deducting non-recurring charge-offs (net of taxes) of $1,703 ($.15 per share) and $4,336 ($.37 per share) for
1995 and 1994, respectively; and reflecting the Appomattox gain (net of taxes) of $905 ($.08 per share) for 1995.
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations.
Earnings Overview.
The Company's 1995 net income was $19.9 million or $1.53 per share of
common stock, which equates to a 10.0% return on average common equity. Net
income and earnings per share of common stock for 1995 compare to $14.8 million
and $1.08 in 1994, and $21.3 million and $1.64 in 1993. The return on average
common equity was 7.2% for 1994 and 11.0% for 1993.
The improved earnings for 1995 result from an $.08 per share gain on the
sale by Catamount Energy Corporation (Catamount), a wholly owned non-utility
subsidiary of the Company, of approximately half of its limited partnership
interest in the Appomattox Cogeneration Limited Partnership; the 5.07% retail
rate increase effective November 1, 1994 and increased retail sales.
In January 1996, the Vermont Public Service Board (PSB) issued an
Accounting Order authorizing the Company to accelerate recovery of
approximately $2.9 million or $.15 per common share of restructuring costs
originally deferred pursuant to a PSB Accounting Order dated March 11, 1994.
As a result of this acceleration, future annual amortization expense, including
the Company's current rate increase request discussed below, will be reduced by
approximately $.8 million through May 1999.
The 1994 net income and earnings per share of common stock were reduced by
approximately $4.3 million and $.37, respectively, for three non-recurring
charges resulting from 1) cost disallowances associated with the PSB Rate Order
which reduced after-tax earnings and earnings per share of common stock by
approximately $1.8 million and $.16, respectively; 2) the Company's decision to
discontinue its proposed new headquarters office building which reduced
after-tax earnings and earnings per share of common stock by $1.7 million and
$.14,
respectively; and 3) writing down SmartEnergy Services, Inc.'s investment in
Green Technologies, Inc.'s (Green Technologies) common stock to reflect
management's estimate in the decline in value of the investment which reduced
after-tax earnings and earnings per share of common stock by $.8 million and
$.07, respectively. Earnings per share of common stock and return on common
equity for 1993 were $1.64 and 11.0%, respectively.
Absent the non-recurring charges and the Appomattox gain, net income and
earnings per share of common stock would have been as follows (dollars in
thousands):
Year Ended December 31
1995 1994 1993
Net income as reported $19,851 $14,800 $21,292
Non-recurring charges,
net of taxes 1,703 4,336 -
Appomattox gain, net of
taxes (905) - -
------- ------- -------
Net income before
non-recurring charges
and Appomattox gain $20,649 $19,136 $21,292
------- ------- -------
Earnings per share of
common stock before
non-recurring charges
and Appomattox gain $1.60 $1.45 $1.64
In 1995, the Company earned 10.75% return on average common equity on its
Vermont utility business and 7.7% return on non-utility investments. The
combined non-utility investments' return on average common equity of 7.7%
resulted from a 9.4% return from Catamount and 10.5% loss from SmartEnergy
Services, Inc. (SmartEnergy). The loss of SmartEnergy was caused primarily by
the write-off of its remaining investment in Green Technologies. See Note 3 to
the Consolidated Financial Statements for additional details on the Company's
non-utility investments.
Principally as a result of increasing purchased power costs, the Company
filed for a 14.6% or $31.0 million general rate increase on October 17, 1995 to
become effective July 1, 1996, to offset the increasing cost of providing
service as more fully discussed below. On February 13, 1996, the Company
reached an agreement with the Vermont Department of Public Service (DPS)
regarding this rate increase request. Under terms of the agreement, the
Company would increase rates 5.5% June 1, 1996 and 2% January 1, 1997. The
agreement effectively caps the Company's allowed return on common equity in its
Vermont retail business for 1996 and 1997 at 11%, by requiring the Company to
reduce deferred Conservation and Load Management (C&LM) costs to the extent its
Vermont retail return on common equity would otherwise exceed 11%. In
addition, the agreement would remove the penalties imposed in a PSB rate order
dated October 31, 1994 discussed in Note 12 to the Consolidated Financial
Statements. The agreement is subject to PSB approval.
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 1995 and 1994 (and the related percentage changes from 1994) is set forth
below:
Percentage Percentage
MWH Sales Increase Revenues (000's) Increase
1995 1994 (Decrease) 1995 1994 (Decrease)
Residential 946,342 954,329 (.8) $103,365 $ 99,991 3.4
Commercial 876,735 860,474 1.9 93,950 89,209 5.3
Industrial 404,487 391,928 3.2 31,565 30,002 5.2
Other retail 7,361 7,564 (2.7) 1,794 1,744 2.9
--------- --------- -------- --------
Total retail sales 2,234,925 2,214,295 0.9 230,674 220,946 4.4
Resale sales:
Firm 4,860 17,469 (72.2) 223 634 (64.8)
Entitlement 895,409 834,304 7.3 39,802 37,220 6.9
Other 580,048 642,802 (9.8) 13,269 14,201 (6.6)
--------- --------- -------- --------
Total resale sales 1,480,317 1,494,575 (1.0) 53,294 52,055 2.4
Other revenues - - 4,309 4,157 3.7
-------- --------- -------- --------
Total 3,715,242 3,708,870 0.2 $288,277 $277,158 4.0
Year-to-year fluctuations in total retail MWH sales are primarily affected
by customer growth, C&LM programs, as well as relative prices of alternate
energy sources, weather patterns and conservation induced by price changes and
income elasticity responses of customers. Total retail MWH sales for 1995
increased .9% compared to 1994. Retail MWH sales declined during the first
quarter of 1995 due to warm weather and its impact on winter recreational
activities. However, retail MWH sales improved throughout the remainder of the
year. Retail revenues for 1995 increased $9.7 million or 4.4% due to an
$8.0 million increase in price resulting from the 5.07% retail rate increase
and $1.8 million associated with the .9% increase in MWH sales.
In anticipation of a more competitive environment and to better align
costs with revenues by rate class, on May 24, 1995, the Company filed with the
PSB a request for a retail rate redesign which would be revenue neutral
overall. The rate redesign, if subsequently approved by the PSB, would
decrease the average rate per kilowatt hour for the commercial and industrial
sectors by approximately 4% and would increase the average rate per kilowatt
hour for the residential sector by about 5%. If approved by the PSB, the rate
redesign will also reduce the gap between peak and off-peak rates. Technical
hearings before the PSB for the proposed rate design changes have been
scheduled for mid-1996.
Due to current market conditions, some of the Company's firm resale
customers chose not to extend their contracts. As a result, firm resale MWH
sales and revenues declined for 1995 and 1994. However, two of those customers
are currently purchasing power from the Company based on market rates.
Entitlement MWH sales and revenues increased 7.3% and 6.9%, respectively,
due to the sale of power purchased from Hydro-Quebec to Boston Edison Company.
However, this increase was partially offset by decreased MWH sales made in
conjunction with a swap arrangement with Commonwealth Electric, which
terminated on October 31, 1995, reduced sell-backs to Hydro-Quebec of purchased
power and reduced sales to UNITIL due to the scheduled refueling and
maintenance shutdown of Vermont Yankee that began on March 17, 1995.
Other resale sales for 1995 decreased 62,754 MWH and related revenues
decreased $.9 million, primarily from lower short-term sales to NEPOOL.
The Company continues to make every effort to maintain or increase resale
sales despite the weak market for capacity and energy in the region.
The table below analyzes the components of increases or decreases in
revenues compared to the prior year (dollars in thousands):
1995 1994
Revenue increase (decrease) from:
Retail MWH sales $ 1,765 $ 826
Retail rates 7,963 2,019
Changes in firm resale sales (411) (2,113)
Changes in entitlement sales 2,582 (5,197)
Changes in other resale sales (932) 8,006
Changes in other revenues 152 (70)
Deferred revenues - (6,075)
------- -------
Net increase (decrease) over prior year $11,119 $(2,604)
======= =======
The increases in retail rates are due to the 5.07% retail rate increase
that became effective with service rendered November 1, 1994.
The decrease in entitlement sales and revenues for 1994 compared to 1993
is due to reduced sell-back of the Hydro-Quebec power, partially offset by
increased sales made in conjunction with a swap arrangement with Commonwealth
Electric as well as higher sales to UNITIL.
The increase in other resale sales for 1994 resulted from increased sales
to NEPOOL and other utilities in New England.
Deferred revenues of $(6.1) million in 1994 relate to the recognition in
1993 of revenues deferred from 1991.
Purchased power The Company purchases approximately 90% of its power needs
under several contracts of varying duration. Over 30% of these purchases are
from affiliated companies whereby the Company receives its entitlement share of
the output. The Company's purchased power portfolio assures that a diversified
mix of sources and fuel types are available to meet the Company's long-term
load growth while providing short and intermediate term opportunities to
purchase or sell capacity and energy to reduce overall power costs. The
percentages of the Company's energy sources were as follows:
Year Ended December 31
1995 1994 1993
Nuclear generating companies 32% 39% 34%
Canadian imports 33 20 28
PSNH--coal 8 7 8
Company-owned hydro 4 5 5
Jointly owned units 4 5 4
Small power producers 5 5 5
Other sources 14 19 16
--- --- ---
100% 100% 100%
=== === ===
The Company has equity ownership interests in four nuclear generating
companies: Vermont Yankee (VY), Maine Yankee (MY), Yankee Atomic (YA) and
Connecticut Yankee (CY).
The VY nuclear plant, which provides approximately one-third of the
Company's power supply, was unavailable from August 27 through October 24, 1993
and from March 17 through May 2, 1995 due to its scheduled refueling outages.
VY also had unscheduled outages from April 7 to April 16, 1993 and December 6
to December 20, 1993.
The MY plant was shut down for refueling and maintenance from July 30
through October 13, 1993. For details relating to MY's 1995 shutdown and the
permanent shutdown of YA, see Note 2 to the Consolidated Financial Statements.
The CY plant was shut down for a scheduled refueling outage from May 15
through July 21, 1993 and from January 28 through April 18, 1995. There were
no scheduled refueling outages and no major unscheduled outages during 1994.
During scheduled refueling outages, the Company purchases more costly
replacement energy from other sources to satisfy energy needs. In accordance
with current rate-making treatment, the Company defers and amortizes to expense
over their respective fuel cycles the incremental replacement energy and
maintenance costs associated with these refueling outages for the Yankee plants
and the Millstone #3 jointly owned nuclear generating unit. During 1995, the
Company deferred $2.4 million and $6.9 million of replacement energy and
capacity costs, respectively, for VY, MY, CY and Millstone #3; and for 1993,
deferred $2.4 million and $6.5 million of energy and capacity costs,
respectively, for VY, MY, CY and Millstone #3.
Under various long-term purchase power contracts expiring in 2016, the
Company receives varying amounts of capacity and energy from Hydro-Quebec. See
Note 13 to the Consolidated Financial Statements for further details related to
the Hydro-Quebec power contracts.
Under a 30-year contract, which expires in 1998, the Company, through
Vermont Electric Power Company, Inc., purchases 46.98 MW of capacity from
Merrimack #2, a coal-fired generating plant owned by Northeast Utilities.
The Company also owns 20 hydroelectric generating units which have a total
nameplate capability of 41.2 MW and two gas-fired and one diesel-peaking units
with a combined nameplate capability of 28.9 MW. 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 #3, an
1149 MW nuclear unit. Millstone #3 was shut down from July 31 through
November 7, 1993 and from April 14 to June 6, 1995 for refueling outages. The
Company's percentage ownership in these units is 20%, 1.78% and 1.73%,
respectively.
The Company, under long-term contracts, purchases power from a number of
small power producers who own qualifying facilities under the Public Utility
Regulatory Policies Act of 1978. These qualifying facilities produce energy
using hydroelectric, wood, biomass and refuse-burning generation. During 1995,
the Company purchased 190,105 MWH of which approximately 135,504 MWH is
associated with the Vermont Power Exchange and 37,822 MWH with a New
Hampshire/Vermont solid waste plant.
The Company engages in purchases and sales with other electric utilities
and with NEPOOL to take advantage of immediate pricing and other market
conditions. These purchases are included in Other sources in the table above.
The net cost components of purchased power and production fuel costs for
the past three years were as follows (dollars in thousands):
1995 1994 1993
Units Amount Units Amount Units Amount
Purchased and produced:
Capacity (MW) 585 $ 85,758 568 $ 83,677 496 $ 86,857
Energy (MWH) 3,603,446 63,907 3,544,563 59,485 3,338,298 59,726
-------- -------- --------
Total purchased power costs 149,665 143,162 146,583
Production fuel (MWH) 348,528 2,358 381,819 1,932 313,020 1,737
-------- -------- --------
Total purchased power and
production fuel costs 152,023 145,094 148,320
Entitlement and other
resale sales (MWH) 1,475,457 53,071 1,477,106 51,421 1,195,068 48,862
-------- -------- --------
Net purchased power and
production fuel costs $ 98,952 $ 93,673 $ 99,458
======== ======== ========
Purchased capacity costs increased $2.1 million for 1995 resulting from a
3% or $2.5 million increase in the amount of MW purchased offset by a favorable
price variance of approximately $.4 million. The decrease of $3.2 million for
1994 resulted from a favorable price variance of $15.7 million offset by an
increase of 14.5% or $12.5 million in the amount of MW purchased. The 1994
variances are primarily due to the absence of refueling outages for Vermont
Yankee.
Energy costs are directly related to the variable prices of oil, nuclear
fuel and coal but, more importantly, to the proportion of the Company's
purchased energy that comes from each of these fuel sources. In total, energy
costs for 1995 increased $4.4 million. Cost per MWH purchased increased 5.7%
or $3.4 million and the amount of MWH purchased increased 1.7% or $1.0 million.
For 1994, energy costs were about the same as 1993. Cost per MWH purchased
decreased 6.2% or $3.9 million offset by an increase of 6.2% or $3.7 million in
the amount of MWH purchased.
The Company is responsible for paying its entitlement percentage of
decommissioning costs for VY, CY, MY and YA as well as its joint ownership
percentage of decommissioning costs for Millstone #3. See Notes 2 and 13 to
the Consolidated Financial Statements. Recently, the staff of the Securities
and Exchange Commission has questioned certain current accounting practices of
the electric utility industry, including the Company, regarding the
recognition, measurement and classification of decommissioning costs for
nuclear generating stations in financial statements of electric utilities. In
response to these questions, the Financial Accounting Standards Board has
agreed to review the industry-wide accounting for nuclear decommissioning
costs. If current electric utility industry accounting practices for such
decommissioning costs are changed, it is possible that annual provisions for
decommissioning costs could increase, the total estimated costs for
decommissioning could be recorded as a liability, and income from external
decommissioning trusts could be reported as investment income instead of a
reduction to decommissioning expense. The Company does not believe that such
changes, if required, would have an adverse effect on results of operations due
to its ability to recover decommissioning costs through the regulatory process.
See Liquidity and Capital Resources - Competition, for related information.
Production fuel costs increased $.4 million for 1995. The increase
results from an increase in price of approximately $.7 million offset by an
8.8% decrease in the amount of MWH generated primarily by one of the Company's
jointly owned units, Millstone #3, due to its scheduled refueling outage. The
1994 increase of $.2 million resulted from a 22.0% or 68,799 MWH increase in
the amount of MWH generated mostly by Millstone #3.
In order to optimize its power mix for baseload, intermediate and peaking
power, the Company engages in sales and purchases with other electric
utilities, primarily in New England and with NEPOOL. These transactions
typically take advantage of immediate pricing and other market conditions. The
profits from these transactions are used to reduce purchased power costs.
As stated earlier, the Company is making every effort to maintain or
increase these sales despite the weak resale market for excess capacity and
energy in the region.
The Company's forecast indicates that net purchased power and production
fuel costs will be approximately $109.4 million, $119.9 million and $130.5
million for the period 1996 through 1998.
Other operation expenses Other operation expenses were relatively flat for
1995 and increased 13.2% or $4.8 million for 1994 primarily due to the
charge-off of approximately $2.9 million in costs related to the proposed new
corporate headquarters office building, an increase in pension and benefit
costs and regulatory commission expenses.
Depreciation The increases in depreciation expense for 1995 and 1994 are due
to property additions and the installation of new computer systems in 1993.
Income taxes Federal and state income taxes fluctuate with the level of
pre-tax earnings. These taxes increased for 1995 as a result of higher
pre-tax
earnings. For 1994, these taxes decreased as a result of lower pre-tax
earnings. However, the decrease was offset by the write-off of $1.6 million of
SFAS No. 109 deferred tax assets which were expected to be collected from
customers through rates. Recovery of these taxes was disallowed by the PSB in
its October 31, 1994 Rate Order.
Other income and deductions Equity in earnings of affiliates increased 6.3%
for 1995 resulting from higher earnings from the Company's nuclear generating
affiliates. For 1994, it decreased 14.3% as compared to 1993. The decrease
was attributable to a lower rate of return allowed by the Federal Energy
Regulatory Commission (FERC) to some of the Company's nuclear generating
affiliates.
The increase in allowance for equity and borrowed funds used during
construction for 1994 is due to increased capital expenditures and higher rates
used for capitalization of these funds.
The increase in other income (expenses), net results primarily from the
$1.5 million pre-tax gain on the sale of a partial interest in the Appomattox
project in 1995 and the $1.3 million write-down of the Company's investment in
Green Technologies during 1994. However, the increase was partially offset by
a $.4 million additional write-off of the Company's investment in Green
Technologies in 1995 to reflect management's estimate of the permanent decline
in the value of the investment. This eliminates SmartEnergy's investment in
Green Technologies. On December 29, 1995, Green Technologies filed for
bankruptcy under Chapter 7.
The decrease of approximately $.9 million for 1994 compared to 1993
reflects the $1.3 million write-down in 1994 partially offset by higher income
from non-utility subsidiaries as well as higher interest on temporary cash
investments due to a combination of higher investment levels and interest rates
during 1994.
Interest on long-term debt Interest on long-term debt for 1995 was about the
same as 1994. The 1994 increase over 1993 results from the issuance of
$43 million of First Mortgage Bonds in December 1993.
Other interest expense Due to increased short-term debt levels and higher
interest rates, other interest expense increased for 1995 compared to 1994.
The 1994 increase of approximately $.4 million was due to the 1993 FERC
settlement related to certain wholesale customers.
Cash Dividends Declared
Preferred
In January 1994, the Company redeemed 280,000 shares of preferred stock 9%
dividend series at a premium of $.25 per share. This redemption resulted in a
decrease in preferred dividends declared for 1995 and 1994.
Common
The decrease in common dividends declared for 1995 results from an
advanced quarterly common dividend declaration in December 1994 payable
February 15, 1995. As a result, the accompanying Consolidated Financial
Statements reflect three quarterly dividend declarations in 1995 and five in
1994. The December 1994 declaration reflected the 44% reduction in dividends
paid per share.
Liquidity and Capital Resources
Competition As described in Note 1 to the Consolidated Financial Statements,
management believes that the Company meets the requirement of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation", but continues to
evaluate significant changes in the regulatory and competitive environment to
ensure and assess the Company's overall consistency with the criteria of SFAS
No. 71. In the future, if 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 an amount that could be
material. Although these conditions do not currently exist, the Company
anticipates future competition will place pressure on both unit sales and the
price the Company can charge. As a result, increased competitive pressure in
the electric utility industry may restrict the Company's ability to establish
prices to recover embedded costs and may lead to a significant change in the
manner rates are set by regulators from cost-based regulation to a different
form of regulation that approximates market conditions. Singly or together
these events may give rise to the discontinuance of SFAS No. 71 and, in
addition, could diminish the Company's ability to recover its embedded costs of
providing service.
Utility Restructuring The electric utility industry is in a period of
potential transition that may result in a shift away from cost of service and
return on equity rates to one with more market based rates. In many states,
including Vermont and New Hampshire, where the Company does business, new
mechanisms are being explored to bring greater competition, customer choice and
market influence to the industry while retaining the public benefits associated
with the current regulatory system.
In Vermont, the PSB by Order dated October 17, 1995, opened a process
requiring all 22 electric utilities in Vermont to file proposed restructuring
plans by mid-1996, facilitating open competition for retail consumers. The
goal, as set forth in the Order, is to achieve restructuring by December 31,
1997. The Company released its vision statement for a restructured electric
industry to interested parties on January 26, 1996.
The Company's vision statement provides for full recovery of prudently
incurred utility investments and obligations that may become stranded as a
result of restructuring in the electric industry. Potentially, costs that are
currently being recovered in rates could become stranded in the future if the
Company were unable to reflect such costs in its rates after restructuring.
Sources of potential stranded costs would include any then above market
purchased power contracts or generation costs, nuclear decommissioning
obligations, unrecovered regulatory assets, as well as other unrecovered
investments and commitments made as a provider of electric utility service.
Recovery of stranded costs would be sought through a mandatory distribution
"wires" charge for access to the distribution system.
The extent of potential stranded costs, if any, depends upon the timing,
nature, and degree of competition that may result from future changes in
regulatory policies governing the Company's activities and prices as well as
future power costs and market prices of power. As such, it is not currently
possible to predict with any reasonable precision the level of costs that could
be considered stranded as a result of future electric utility industry
restructuring. However, it is possible that stranded cost exposure could
exceed the Company's current total common stock equity.
In New Hampshire, the New Hampshire Public Utilities Commission (NHPUC),
directed by the New Hampshire legislature, has begun the process of
establishing a Pilot Program (Pilot) to determine the implications of retail
competition in the electric utility industry. The Pilot is for a three-year
period beginning May 1, 1996 and will be open to all electric utilities and to
all classes of customers in New Hampshire, although only a small percentage of
customers will be selected to participate. Connecticut Valley Electric Company
Inc. (Connecticut Valley), the Company's wholly owned New Hampshire subsidiary,
will be able to compete as a full or partial service provider to retain its
customers and to acquire additional load currently served by other New
Hampshire utilities. Connecticut Valley has engaged in a collaborative process
with interested parties, including NHPUC staff, and has proposed a
recommendation for implementation of the Pilot in its service territory.
Construction The Company's liquidity is primarily affected by the level of
cash generated from operations and the funding require-ments of its ongoing
construction and C&LM programs. Net cash provided by operating activities
generated $41.7 million in 1995, $49.4 million in 1994 and $36.8 million in
1993.
The Company ended the 1995 year with cash and cash equivalents of
$12.0 million, an increase of $4.4 million from the beginning of the year. The
increase in cash for 1995 was the result of $41.7 million provided by operating
activities, $21.8 million used for investing activities and $15.5 million used
for financing activities.
Operating Activities Approximately $39.6 million was provided from net income
before non-cash items, primarily depreciation and deferred income taxes. About
$5.7 million was provided from other operation activities, including C&LM
programs, restructuring costs and net deferral/amortization of nuclear
replacement energy and maintenance costs, while $3.6 million was applied to
fluctuations in working capital.
Investing Activities Construction and plant expenditures consumed
approximately $21.3 million, about $3.9 million was used for C&LM programs, $.3
million was used for non-utility investments and $2.7 million was deposited in
a special account in anticipation of a non-utility investment. Proceeds of
$6.4 million were generated from the sale of a partial interest in a
non-utility investment.
Financing Activities Dividends paid on common stock were $9.3 million, while
preferred stock dividends were $2.0 million. Dividends paid on common stock
for 1995 reflect the 44% reduction from the 1994 level. Short-term obligations
provided $2.0 million while retirement of long-term debt and the repurchase of
common stock required $4.3 million and $1.9 million, respectively.
Excluding allowance for funds used during construction, construction
expenditures are estimated at $21.8 million, $21.5 million, $17.7 million,
$17.6 million and $19.3 million for the years 1996 through 2000, respectively.
These spending levels are consistent with the Company's goal to move toward
limiting annual capital expenditures to annual depreciation.
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.
Short-term borrowings are supported by committed lines of credit and
uncommitted loan facilities with several banks totaling $37.25 million.
Short-term borrowings generally are reduced when long-term debt or equity
securities
are issued. In December 1993, the Company issued $43 million of long-term
debt, of which $14.5 million replaced First Mortgage Bonds redeemed in October
1993 and $4.325 million replaced First Mortgage Bonds redeemed in January 1994.
The balance was used to reduce short-term debt outstanding. In December 1994,
the Company's wholly owned New Hampshire subsidiary, Connecticut Valley, issued
a promissory note of $2.5 million under a five-year loan agreement. The
proceeds were used to repay its 9 1/2% note of $2.5 million held by the parent
company. In the past, the Company has been able to finance its construction
and C&LM programs out of net-cash generated by operating activities and it
expects to meet future commitments in the same manner.
On November 8, 1994, the Board of Directors (Board) reduced the quarterly
dividend rate from $.355 to $.20. As a result, the annual dividend of $1.42
was reduced 44% to $.80 effective with the first quarter dividend paid in
February 1995. Also, the Board authorized the purchase of up to 2 million
shares of its outstanding common stock from time to time in open market
transactions. Through December 31, 1995, the Company had purchased 195,100
shares at an average price of $13.42 per share. These transactions are
recorded as treasury stock, at cost, in the Company's Consolidated Balance
Sheet.
No shares of common stock were purchased by the Company subsequent to
December 31, 1995.
In January 1994, the Company redeemed $7 million of the 9.00% Series
Preferred Stock, $25 par value.
Beginning in August 1994, Dividend Reinvestment and Common Stock Purchase
Plan, and Employee Stock Ownership Plan requirements are satisfied by the
purchase of shares of common stock on the open market.
The Company's capital structure ratios (including amounts of long-term
debt due within one year) for the past three years were as follows:
December 31
1995 1994 1993
Common stock equity 55% 53% 52%
Preferred stock 8 9 10
Long-term debt 37 38 38
--- --- ---
100% 100% 100%
=== === ===
On July 21, 1994 and on August 5, 1994, Duff & Phelps, Inc. (Duff &
Phelps) and Standard & Poor's Corporation (Standard & Poor's), respectively,
lowered their rating on the Company's First Mortgage Bonds and Preferred Stock.
Duff & Phelps stated that the downgrade reflected its concerns about the
continuing recession in New England, intensifying competition in the utility
industry and excess power in the northeastern region, as well as the Company's
loss of wholesale revenues. Standard & Poor's stated "the downgrade reflected
the Company's weak financial profile, adjusted for off-balance sheet
obligations, primarily associated with purchased power, combined with the
Company's low average business position, as well as, restrictive Vermont
regulation, the state of the Vermont economy, nuclear asset concentration and
increasing investments into non-regulated businesses are other factors
impacting the Company's business position". Standard & Poor's also revised its
ratings outlook on the Company to "stable" from "negative".
Current credit ratings for the Company's securities as of February 1996
are as follows:
Duff & Standard
Phelps & Poor's
First Mortgage Bonds BBB+ BBB
Preferred Stock BBB- BBB-
Non-Utility Catamount Energy Corporation, a wholly owned subsidiary of the
Company, maintains an Irrevocable Standby Letter of Credit with a bank to
borrow up to an aggregate amount of $1.2 million to replace its share of cash
in the Appomattox Cogeneration Limited Partnership's Project Debt Service
Reserve Fund. This Letter of Credit is for a one-year term with annual
extensions available and requires fees of 1.5% of credit available.
SmartEnergy, also a wholly owned subsidiary of the Company, maintains a
$1.0 million revolving line of credit with a bank to provide working capital
and financing assistance for investment purposes.
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 1994 and 1995 were $7.9 million and $4.8 million, respectively, and are
expected to be approximately $5.1 million in 1996.
On April 7, 1995, the Company and the DPS jointly filed a Stipulation
resolving issues related to the role of fuel switching as a C&LM resource,
promotion of electricity, and C&LM spending levels for 1995 and 1996. This
Stipulation resolves the outstanding material issues related to C&LM until the
end of 1996. It also establishes a process to remove the return on equity
penalty related to "the Company's failed efforts to acquire all cost-effective
energy efficiency resources" imposed by the PSB in the Company's last rate
case. Although not yet approved by the PSB, the parties are implementing the
Stipulation as outlined in its terms. The parties have recommended that the
PSB remove the return on equity penalty related to the C&LM programs because
the Company has met the conditions outlined in the stipulation.
Diversification Catamount was formed for the purpose of investing in
non-regulated energy-related projects. Currently, Catamount, through its wholly
owned subsidiaries, has interests in six operating independent power projects
located in Rumford, Maine; East Ryegate, Vermont; Hopewell, Virginia; Williams
Lake, British Columbia, Canada; and Glenns Ferry and Rupert, Idaho.
SmartEnergy was formed for the purpose of profitably providing reliable,
energy-efficient products and services, including the rental of electric water
heaters.
Rates and Regulation The Company recognizes 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. The Company filed for a
14.6% or $31.0 million general rate increase on October 17, 1995 to become
effective July 1, 1996, to offset the increasing cost of providing service.
Approximately $29.0 million or 93.5% of the rate increase request is to recover
increased purchased power costs. As part of the rate filing, the Company
proposed a special "Lifeline" program for low-income customers which, if
approved, would serve to limit some of the impact of the rate case and rate
design on residential low-income customers. On February 13, 1996, the Company
reached an agreement with the DPS regarding this rate increase request. For
detail, see Earnings Overview.
At the Company's 1994 Annual Meeting, shareholders approved two amendments
to the Company's Articles of Incorporation subject to obtaining the necessary
regulatory approval. One of the amendments was a so-called Fair Price
provision. The other amendment served to limit the Board's liability in
certain circumstances. Because under Vermont law the Company cannot amend its
Articles of Incorporation without the PSB's permission, the Company filed a
petition seeking the necessary regulatory approval. The DPS vigorously opposed
both amendments, significantly decreasing the likelihood of obtaining PSB
approval. The case was further complicated by the intervention of one of the
plaintiffs in the lawsuit discussed in Note 13 to the Consolidated Financial
Statements. In light of the limited prospect of obtaining regulatory approval,
as well as the ongoing costs associated with the proceeding, the Company
decided to withdraw the petition with prejudice. Accordingly, on October 17,
1995, the Company filed a notice of withdrawal, which the PSB granted.
Inflation The annual rate of inflation, as measured by the Consumer Price
Index, was 2.5% for 1995 and 2.7% for 1994 and 1993. The Company's revenues,
however, are based on rate regulation that generally recognizes only historical
costs. Although the rate of inflation has eased in recent years, it continues
to have an impact on most aspects of the business.
New Accounting Pronouncements Effective January 1, 1996, the Company adopted
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of" and decided not to adopt the accounting
option
of SFAS No. 123, "Accounting for Stock-Based Compensation". Refer to Note 14
to the Consolidated Financial Statements for additional information regarding
these pronouncements.
Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements and Supplementary Data
Page No.
Report of Independent Public Accountants 35
Financial Statements:
Consolidated Statement of Income for each of the
three years ended December 31, 1995 36
Consolidated Statement of Cash Flows for each of
the three years ended December 31, 1995 37
Consolidated Balance Sheet at December 31, 1995
and 1994 38
Consolidated Statement of Capitalization at
December 31, 1995 and 1994 39
Consolidated Statement of Changes in Common Stock
Equity for each of the three years ended
December 31, 1995 40
Notes to Consolidated Financial Statements 41
Report of Independent Public Accountants
To the Board of Directors of
Central Vermont Public Service Corporation:
We have audited the accompanying consolidated balance sheet and statement
of capitalization of Central Vermont Public Service Corporation and its wholly
owned subsidiaries as of December 31, 1995 and 1994, and the related
consolidated statements of income, changes in common stock equity and cash
flows for each of the three years in the period ended December 31, 1995. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Central Vermont Public
Service Corporation and its wholly owned subsidiaries as of December 31, 1995
and 1994 and the results of their operations and cash flows for each of the
three years in the period ended December 31, 1995 in conformity with generally
accepted accounting principles.
ARTHUR ANDERSEN LLP
Boston, Massachusetts
February 5, 1996
CONSOLIDATED STATEMENT OF INCOME
(Dollars in thousands, except per share amounts)
Year Ended December 31
1995 1994 1993
Operating Revenues $288,277 $277,158 $279,389
Operating Expenses
Operation
Purchased power 149,665 143,162 146,583
Production and transmission 20,883 21,122 21,188
Other operation 42,116 40,691 35,933
Maintenance 12,874 12,245 11,719
Depreciation 17,297 16,478 15,402
Other taxes, principally property taxes 10,543 10,423 10,022
Taxes on income 10,662 11,934 12,496
-------- -------- --------
Total operating expenses 264,040 256,055 253,343
-------- -------- --------
Operating Income 24,237 21,103 26,046
-------- -------- --------
Other Income and Deductions
Equity in earnings of affiliates 3,292 3,098 3,613
Allowance for equity funds during construction 243 232 35
Other income (expenses), net 2,493 (27) 827
Benefit (provision) for income taxes (246) 525 (276)
-------- -------- --------
Total other income and deductions, net 5,782 3,828 4,199
-------- -------- --------
Total Operating and Other Income 30,019 24,931 30,245
-------- -------- --------
Interest Expense
Interest on long-term debt 9,544 9,611 8,804
Other interest 798 657 226
Allowance for borrowed funds during construction (174) (137) (77)
-------- -------- --------
Total interest expense, net 10,168 10,131 8,953
-------- -------- --------
Net Income 19,851 14,800 21,292
Preferred Stock Dividends Requirements 2,028 2,138 2,658
-------- -------- --------
Earnings Available For Common Stock $ 17,823 $ 12,662 $ 18,634
======== ======== ========
Average Shares of Common Stock Outstanding 11,648,981 11,716,926 11,383,109
Earnings Per Share of Common Stock $1.53 $1.08 $1.64
Dividends Paid Per Share of Common Stock $ .80 $1.42 $1.42
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)
Year Ended December 31
1995 1994 1993
Cash Flows Provided (Used) By
Operating Activities
Net income $ 19,851 $ 14,800 $ 21,292
Adjustments to reconcile net income to net cash
provided by operating activities
Deferred revenues - - (7,507)
Depreciation 17,297 16,478 15,402
Write-down investment 424 1,332 -
Write-off corporate headquarters costs - 2,857 -
Deferred income taxes and investment tax credits 2,707 3,522 9,615
Allowance for equity funds during construction (243) (232) (35)
Net deferral and amortization of nuclear
replacement energy and maintenance costs (3,299) 5,353 (3,797)
Gain on sale of non-utility investment (1,517) - -
Amortization of conservation & load management
costs 3,362 1,128 2,192
Amortization of restructuring costs 3,937 632 -
(Increase) decrease in accounts receivable (1,280) (1,598) 1,127
Increase (decrease) in accounts payable 1,803 (1,298) (3,475)
Increase (decrease) in accrued income taxes (2,500) 3,209 (2,991)
Decrease in other working capital items (1,576) 1,916 2,028
Other, net 2,745 1,327 2,988
-------- -------- --------
Net cash provided by operating activities 41,711 49,426 36,839
-------- -------- --------
Investing Activities
Construction and plant expenditures (21,337) (22,621) (20,519)
Deferred conservation and load management expenditures (3,899) (6,159) (9,874)
Investments in affiliates 249 150 290
Proceeds from sale of non-utility investment 6,400 - -
Special deposit (2,686) 2,950 (2,950)
Non-utility investments (226) (2,344) (4,475)
Other investments, net (316) (423) (382)
-------- -------- --------
Net cash used for investing activities (21,815) (28,447) (37,910)
-------- -------- --------
Financing Activities
Issuance of long-term debt - 2,500 43,400
Sale of common stock - 3,988 8,325
Repurchase of common stock (1,892) (735) -
Short-term debt, net 1,994 10,155 (744)
Retirement of preferred stock - (7,070) -
Retirement of long-term debt (4,245) (5,382) (34,227)
Common and preferred dividends paid (11,350) (18,845) (18,145)
Other - (16) (26)
-------- -------- --------
Net cash used for financing activities (15,493) (15,405) (1,417)
-------- -------- --------
Net Increase (Decrease) In Cash and Cash Equivalents 4,403 5,574 (2,488)
Cash and Cash Equivalents at Beginning of Year 7,559 1,98 4,473
-------- -------- --------
Cash and Cash Equivalents at End of Year $ 11,962 $ 7,559 $ 1,985
======== ======== ========
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized) $ 9,927 $ 9,673 $ 9,991
Income taxes (net of refunds) $ 7,721 $ 4,687 $ 5,337
Non-cash Investing and Financing Activities
Regulatory assets (Notes 2 and 11)
Long-term lease arrangements (Note 13)
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEET
(Dollars in thousands)
December 31
1995 1994
Assets
Utility Plant, at original cost $453,784 $434,059
Less accumulated depreciation 136,057 125,800
-------- --------
317,727 308,259
Construction work in progress 8,108 15,099
Nuclear fuel, net 1,167 1,197
-------- --------
Net utility plant 327,002 324,555
-------- --------
Investments and Other Assets
Investments in affiliates, at equity 26,464 26,765
Non-utility investments 22,622 28,184
Non-utility property, less accumulated depreciation 2,896 2,989
-------- --------
Total investments and other assets 51,982 57,938
-------- --------
Current Assets
Cash and cash equivalents 11,962 7,559
Special deposits 3,868 575
Accounts receivable 21,374 20,523
Unbilled revenues 11,177 10,696
Materials and supplies, at average cost 4,023 4,182
Prepayments 3,607 3,544
Other current assets 4,564 4,231
-------- --------
Total current assets 60,575 51,310
-------- --------
Regulatory Assets and Other Deferred Charges 50,503 56,596
-------- --------
Total Assets $490,062 $490,399
======== ========
Capitalization And Liabilities
Capitalization
Common stock equity $179,760 $170,784
Preferred and preference stock 8,054 8,054
Preferred stock with sinking fund requirements 20,000 20,000
Long-term debt 120,142 120,157
-------- --------
Total capitalization 327,956 318,995
-------- --------
Long-term Lease Arrangements 19,385 20,467
-------- --------
Current Liabilities
Short-term debt 13,505 11,511
Current portion of long-term debt - 4,230
Accounts payable 4,726 5,970
Accounts payable - affiliates 10,559 8,435
Accrued income taxes 1,497 3,997
Dividends declared 507 2,853
Other current liabilities 26,101 26,673
-------- --------
Total current liabilities 56,895 63,669
-------- --------
Deferred Credits
Deferred income taxes 57,191 52,710
Deferred investment tax credits 8,003 8,394
Other deferred credits 20,632 26,164
-------- --------
Total deferred credits 85,826 87,268
-------- --------
Commitments and Contingencies
Total Capitalization and Liabilities $490,062 $490,399
======== ========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CAPITALIZATION
(Dollars in thousands)
December 31
1995 1994
Common Stock Equity
Common stock, $6 par value, authorized 19,000,000
shares; outstanding 11,785,848 shares $ 70,715 $ 70,715
Other paid-in capital 45,251 45,229
Treasury stock (195,100 shares and 56,400 shares,
respectively, at cost) (2,628) (735)
Retained earnings 66,422 55,575
-------- --------
Total common stock equity 179,760 170,784
-------- --------
Cumulative Preferred and Preference Stock
Preferred stock, $100 par value, authorized
500,000 shares
Outstanding:
Non-redeemable
4.15 % Series; 37,856 shares 3,786 3,786
4.65 % Series; 10,000 shares 1,000 1,000
4.75 % Series; 17,682 shares 1,768 1,768
5.375% Series; 15,000 shares 1,500 1,500
Redeemable
8.30 % Series; 200,000 shares 20,000 20,000
Preferred stock, $25 par value, authorized
1,000,000 shares
Outstanding - none - -
Preference stock, $1 par value, authorized
1,000,000 shares
Outstanding - none - -
-------- --------
Total cumulative preferred and preference stock 28,054 28,054
-------- --------
Long-Term Debt
First Mortgage Bonds
5 1/8% Series M , due 1995 - 4,230
9.20 % Series EE, due 1998 7,500 7,500
9.20 % Series FF, due 2000 7,500 7,500
9.26 % Series GG, due 2002 3,000 3,000
9.97 % Series HH, due 2003 25,000 25,000
8.91 % Series JJ, due 2031 15,000 15,000
5.30 % Series KK, due 1998 10,000 10,000
5.54 % Series LL, due 2000 5,000 5,000
6.01 % Series MM, due 2003 7,500 7,500
6.27 % Series NN, due 2008 3,000 3,000
6.90 % Series OO, due 2023 17,500 17,500
Vermont Industrial Development Authority Bonds
Variable, due 2013 (4.25% at December 31, 1995) 5,800 5,800
New Hampshire Industrial Development Authority Bonds
6 7/8%, due 2009 5,500 5,500
Connecticut Development Authority Bonds
Variable, due 2015 (3.50% at December 31, 1995) 5,000 5,000
Other, various 2,842 2,857
-------- --------
120,142 124,387
Less current portion - 4,230
-------- --------
Total long-term debt 120,142 120,157
-------- --------
Total Capitalization $327,956 $318,995
======== ========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCK EQUITY
(Dollars in thousands)
Other
Common Stock Paid-in Treasury Retained
Shares Amount Capital Stock Earnings Total
Balance, December 31, 1992 11,196,576 $67,180 $36,472 $ - $ 55,438 $159,090
Sale of common stock 365,643 2,193 6,132 8,325
Net income 21,292 21,292
Cash dividends on capital stock:
Common stock - $1.42 per share (12,193) (12,193)
Cumulative preferred stock:
Non-redeemable (998) (998)
Redeemable (1,660) (1,660)
Common stock issuance expenses (26) (26)
Amortization of preferred stock
issuance expenses 6 6
---------- ------- ------- ------- -------- --------
Balance, December 31, 1993 11,562,219 69,373 42,584 - 61,879 173,836
Sale of common stock 223,629 1,342 2,646 3,988
Treasury stock at cost (56,400) (735) (735)
Net income 14,800 14,800
Cash dividends on capital stock:
Common stock - $1.42 per share (16,620) (16,620)
Common stock - $.20 per share (2,346) (2,346)
Cumulative preferred stock:
Non-redeemable (408) (408)
Redeemable (1,660) (1,660)
Premium (70) (70)
Common stock issuance expenses (16) (16)
Amortization of preferred stock
issuance expenses 15 15
---------- ------- ------- ------- -------- --------
Balance, December 31, 1994 11,729,448 70,715 45,229 (735) 55,575 170,784
Treasury stock at cost (138,700) (1,893) (1,893)
Net income 19,851 19,851
Cash dividends on capital stock:
Common stock - $.80 per share (6,976) (6,976)
Cumulative preferred stock:
Non-redeemable (368) (368)
Redeemable (1,660) (1,660)
Amortization of preferred stock
issuance expenses 22 22
---------- ------- ------- ------- -------- --------
Balance, December 31, 1995 11,590,748 $70,715 $45,251 $(2,628) $ 66,422 $179,760
---------- ------- ------- ------- -------- --------
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1
Summary of significant accounting policies
Consolidation The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries.
Regulation The Company is subject to regulation by the Vermont Public Service
Board (PSB), the Federal Energy Regulatory Commission (FERC) and, to a lesser
extent, the public utilities commissions in other New England states where the
Company does business, with respect to rates charged for service, accounting
and other matters pertaining to regulated operations. As such, the Company
currently prepares its financial statements in accordance with Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation", and records various regulatory assets and
liabilities. In order for a Company to report under SFAS No. 71, the Company's
rates must be designed to recover its costs of providing service, and the
Company must be able to collect those rates from customers. If rate recovery
of these costs becomes unlikely or uncertain, whether due to competition or
regulatory action, these accounting standards may no longer apply to the
Company's regulated operations. Management believes that the Company currently
meets the criteria for continued application of SFAS No. 71, but will continue
to evaluate significant changes in the regulatory and competitive environment
to assess the Company's overall consistency with the criteria of SFAS No. 71.
In the event the Company determines that it no longer meets the criteria for
applying SFAS No. 71, the accounting impact would be an extraordinary non-cash
charge to operations of an amount that could be material.
Revenues Estimated unbilled revenues are recorded at the end of accounting
periods. Unbilled revenues of approximately $18.3 million, $18.5 million and
$18.7 million for 1993, 1994 and 1995, respectively, are included in revenues
on the Consolidated Statement of Income.
Maintenance Maintenance and repairs, including replacements not qualifying as
retirement units of property, are charged to maintenance expense. Replacements
of retirement units are charged to utility plant. The original cost of units
retired plus the cost of removal, less salvage, is charged to the accumulated
provision for depreciation.
Depreciation The Company uses the straight-line remaining life method of
depreciation. Total depreciation expense was approximately 3.6% of the cost of
depreciable utility plant for each of the years 1993 through 1995.
Income Taxes The Company records income taxes in accordance with SFAS No. 109,
"Accounting for Income Taxes", which requires an asset and liability approach
to determine income tax liabilities. The standard recognizes tax assets and
liabilities for the cumulative effect of all temporary differences between
financial statement carrying amounts and the tax basis of assets and
liabilities, see Note 11. Investment tax credits associated with utility plant
are deferred and amortized ratably to income over the lives of the related
properties. Investment tax credits associated with non-utility plant are
recognized as income in the year realized.
Allowance for Funds During Construction Allowance for funds used during
construction (AFDC) is the cost, during the period of construction, of debt and
equity funds used to finance construction projects. The Company capitalizes
AFDC as a part of the cost of major utility plant projects to the extent that
costs applicable to such construction work in progress have not been included
in rate base in connection with rate-making proceedings. AFDC equity
represents a current non-cash credit to earnings which is recovered over the
life of the property. The AFDC rates used by the Company were 5.09%, 8.05% and
8.41% for the years 1993 through 1995, respectively.
Regulatory Assets and Other Deferred Charges Certain costs are deferred and
amortized in accordance with authorized or expected rate-making treatment. The
major components of these costs are $20.5 million for Conservation and Load
Management, $9.1 million for SFAS No. 109, $7.9 million for Yankee Atomic
Electric Company dismantling costs, and $4.4 million of energy and capacity
deferrals. During regular nuclear refueling outages, the increased costs
attributable to replacement energy purchased from NEPOOL and maintenance costs
are deferred and amortized ratably to expense until the next regularly
scheduled refueling shutdown. The Company earns a return on the unamortized
replacement energy and maintenance costs. See Note 2 to the Consolidated
Financial Statements for discussion of the costs associated with the
discontinued operation of the Yankee Atomic Nuclear Power Corporation nuclear
power plant.
Purchased Power The Company records the annual cost of power obtained under
long-term contracts as operating expenses. Since these contracts, as more
fully described in Note 13, do not convey to the Company the right to use
property, plant, or equipment, they are considered executory in nature. This
accounting treatment is in contrast to the Company's commitment with respect to
the Hydro Quebec Phase I and II transmission facilities which are considered
capital leases. As such, the Company has recorded a liability for its
commitment under the Phase I and II arrangements and recognized an asset for
the right to use these facilities.
Use of Estimates The Company's Consolidated Financial Statements required the
use of certain estimates, based on management's judgement, in determing the
Company's assets, liabilities, revenue and expenses.
Statement of Cash Flows The Company considers all highly liquid investments
with a maturity of three months or less when acquired to be cash equivalents.
Reclassifications Certain reclassifications have been made to prior year
Consolidated Financial Statements to conform with the 1995 presentation.
Note 2
Investments in affiliates
The Company uses the equity method to account for its investments in the
following companies (dollars in thousands):
December 31
Ownership 1995 1994
Nuclear generating companies:
Vermont Yankee Nuclear Power Corporation 31.3% $16,740 $16,916
Connecticut Yankee Atomic Power Company 2.0% 2,021 2,011
Maine Yankee Atomic Power Company 2.0% 1,412 1,338
Yankee Atomic Electric Company 3.5% 820 813
------- -------
20,993 21,078
Vermont Electric Power Company, Inc.:
Common stock 56.8% 3,496 3,494
Preferred stock 1,975 2,193
------- -------
$26,464 $26,765
======= =======
Each sponsor of the nuclear generating companies is obligated to pay an
amount equal to its entitlement percentage of fuel, operating expenses
(including decommissioning expenses) and cost of capital and is entitled to a
similar share of the power output of the plants. The Company's entitlement
percentages are identical to the ownership percentages except that Vermont
Yankee's entitlement percentage is 35%. The Company is obligated to contribute
its entitlement percentage of the capital requirements of Vermont Yankee and
Maine Yankee and has a similar, but limited, obligation to Connecticut Yankee.
The Company is responsible for paying its entitlement percentage of
decommissioning costs for Vermont Yankee, Connecticut Yankee, Maine Yankee and
Yankee Atomic as follows (dollars in millions):
CVPS's
Total Share of
Date of Estimated CVPS's Funded
Study Obligation Obligation Obligation
Nuclear generating companies:
Vermont Yankee 1993 $312.7 $109.4 $47.1
Maine Yankee 1993 $316.6 $6.3 $2.8
Connecticut Yankee 1992 $309.0 $6.2 $3.6
Yankee Atomic 1994 $370 $13.0 $3.9
In 1992, the Board of Directors of Yankee Atomic decided to permanently
discontinue operation of their plant, and to decommission the facility.
The Company relied on Yankee Atomic for less than 1.5% of its system
capacity. Presently, purchased power costs billed to the Company by Yankee
Atomic, which include a provision for ultimate decommissioning of the unit, are
being collected from the Company's customers via existing retail rate tariffs.
In 1995, the FERC approved a new settlement agreement regarding the
decommissioning plan, recovery of plant investment and all issues with respect
to the prudence of the decision to discontinue operation.
The Company's total current share of its cost with respect to Yankee
Atomic's decision to discontinue operation is approximately $7.9 million. This
amount is reflected in the accompanying balance sheet both as a regulatory
asset and deferred power contract obligation (current and non-current).
The Company believes that its proportionate share of Yankee Atomic costs
will be recovered through the regulatory process and, therefore, the ultimate
resolution of the premature retirement of the Yankee Atomic plant has not and
will not have a material adverse effect on the Company's earnings or financial
condition.
The Company owns 2% of the common stock of Maine Yankee and is entitled to
approximately 2% of the power output of the 880-megawatt nuclear generating
plant (Plant) located in Wiscasset, Maine.
During the refueling and maintenance shutdown that commenced in early
February 1995, Maine Yankee detected an increased rate of degradation of the
Plant's steam generator tubes well above its expectations and began evaluating
several courses of action.
On May 22, 1995, Maine Yankee announced its plan to repair the tubes in
the plant's three steam generators by sleeving all 17,000 steam generator
tubes. The sleeving process was completed in December 1995 at a total cost of
approximately $28 million. The Company's share of the cost to repair the steam
generator tubes was about $.6 million. The Plant returned to service at 90% of
its 880-megawatt rating in January 1996. The Company's additional costs for
replacement power while Maine Yankee was not operating was $1.2 million.
Costs incurred for unanticipated replacement power and steam generator
repairs amounting to approximately $1.8 million have been included in the
Company's 1995 results of operations.
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 Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $8.9 billion. Beyond that a licensee
maintains an indemnity agreement with the Nuclear Regulatory Commission, but
subject to Congressional approval. The first $200 million of liability
coverage is the maximum provided by private insurance. The Secondary Financial
Protection Program is a retrospective insurance plan providing additional
coverage up to $8.7 billion per incident by assessing $79.3 million against
each of the 110 reactor units that are currently subject to the Program in the
United States, limited to a maximum assessment of $10 million per incident per
nuclear unit in any one year. The maximum assessment is to be adjusted at
least every five years to reflect inflationary changes. The Company's
interests in the nuclear power units are such that it could become liable for
an aggregate of approximately $4.1 million of such maximum assessment per
incident per year.
Summarized financial information for Vermont Yankee Nuclear Power
Corporation is as follows (dollars in thousands):
Earnings 1995 1994 1993
Operating revenues $180,437 $162,757 $180,145
Operating income $15,006 $14,355 $16,441
Net income $6,790 $6,588 $7,794
Company's equity in net income $2,111 $2,067 $2,434
December 31
Investment 1995 1994
Current assets $ 52,267 $ 41,416
Non-current assets 479,026 470,726
Total assets 531,293 512,142
Less:
Current liabilities 25,058 29,115
Non-current liabilities 452,292 428,554
-------- --------
Net assets $ 53,943 $ 54,473
-------- --------
Company's equity in net assets $ 16,740 $ 16,916
Included in Vermont Yankee's revenues shown above are sales to the Company
of $52.3 million, $53.6 million and $52.9 million for 1993 through 1995,
respectively. These amounts are reflected as purchased power net of deferrals
and amortization in the accompanying Consolidated Statement of Income.
Vermont Electric Power Company, Inc. (Velco) and its wholly owned
subsidiary Vermont Electric Transmission Company, Inc. own and operate
transmission systems in Vermont over which bulk power is delivered to all
electric utilities in the state. Velco has entered into transmission
agreements with the state of Vermont and the electric utilities and under these
agreements bills all costs, including interest on debt and a fixed return on
equity, to the state and others using the system. These contracts enable Velco
to finance its facilities primarily through the sale of first mortgage bonds.
Included in Velco's revenues shown below are transmission services to the
Company (reflected as production and transmission in the accompanying
Consolidated Statement of Income) amounting to $8.9 million, $8.4 million and
$7.9 million for 1993 through 1995, respectively.
Velco operates pursuant to the terms of the 1985 Four-Party Agreement (as
amended) with the Company and two other major distribution companies in
Vermont. Although the Company owns 56.8% of Velco's outstanding common stock,
the Four-Party Agreement effectively restricts the Company's control of Velco.
Therefore, Velco's financial statements have not been consolidated. The
Four-Party Agreement continues in full force and effect until May 1997 and
will be
extended for an additional two-year term in May 1997, and every two years
thereafter, unless at least ninety (90) days prior to any two-year anniversary
any party shall notify the other parties in writing that it desires to
terminate the agreement as of such anniversary. No such notification has been
filed by the parties. The Company also owns 46.6% of Velco's outstanding
preferred stock, $100 par value.
Summarized financial information for Velco is as follows (dollars in
thousands):
Earnings 1995 1994 1993
Transmission revenues $16,398 $16,761 $17,891
Operating income $2,767 $3,350 $4,423
Net income $1,297 $1,296 $1,375
Company's equity in net income $650 $638 $698
December 31
Investment 1995 1994
Current assets $22,121 $16,549
Non-current assets 49,547 53,175
------- -------
Total assets 71,668 69,724
Less:
Current liabilities 22,045 15,941
Non-current liabilities 39,193 42,909
------- -------
Net assets $10,430 $10,874
======= =======
Company's equity in net assets $ 5,471 $ 5,687
Note 3
Non-utility investments
The Company's wholly owned subsidiary, Catamount Energy Corporation
(Catamount) invests through its wholly owned subsidiaries in non-regulated,
energy-related projects. Certain financial information for Catamount's
investments is set forth in the table that follows (dollars in thousands):
Investment
Generating In Service December 31
Projects Location Capacity Fuel Date Ownership 1995 1994
Rumford Cogeneration Co. L.P. (Rumford) Maine 85MW Coal/Wood 1990 15.1% $10,275 $9,804
Ryegate Associates (Equinox) Vermont 20MW Wood 1992 33.1% $ 6,671 $6,587
Appomattox Cogeneration L.P. (Appomattox) Virginia 41MW Coal/Wood 1982 25.3% $ 4,521 $9,819
Black liquor
NW Energy Williams Lake L.P. British Columbia, 60MW Wood 1993 8.1% $ 1,155 $1,550
(Williams Lake) Canada
Glenns Ferry Cogeneration Partners, Ltd. Idaho 10MW Gas 1996 50.0% - -
Rupert Cogeneration Partners, Ltd. Idaho 10MW Gas 1996 50.0% - -
On October 26, 1992, Catamount purchased a 50% partnership interest in
Appomattox Cogeneration L.P., which owns a power sales agreement associated
with a cogeneration facility currently in operation.
On July 21, 1995, Catamount sold approximately half of its limited
partnership's interest in Appomattox. The sale generated capital to fund new
investments in independent power projects. The sale resulted in a $1.5 million
gain (pre-tax) and added approximately $.08 to earnings per common share during
the third quarter of 1995. Upon closing, Catamount's ownership percentage in
Appomattox was reduced to 25.25%.
On October 2, 1995, Catamount's Board of Directors voted to invest,
through wholly owned subsidiaries of Catamount, up to $3.1 million to purchase
50% interests in two 10MW gas-fired cogeneration projects to be constructed in
Glenns Ferry and Rupert, Idaho. At December 31, 1995, Catamount had $2.7
million in an escrow account in anticipation of this closing. Both plants are
scheduled to come on line by the end of 1996.
SmartEnergy Services, Inc. (SmartEnergy) also is a wholly owned subsidiary
of the Company, whose purpose is to profitably provide reliable, energy
efficient products and services, including the rental of electric water
heaters.
On October 1, 1993, SmartEnergy purchased for $1.2 million, 304,125 shares
(5%) of Green Technologies common stock and on September 19, 1994, purchased
for $540,000, an additional 120,000 shares (1.8%). This investment increased
SmartEnergy's ownership in Green Technologies to 6.8%. Green Technologies of
Boulder, Colorado, manufactured Green Plug electricity savers for several types
of household appliances. During the fourth quarter of 1994, SmartEnergy
wrote-down its investment in Green Technologies by approximately $1.3 million
and during the third quarter of 1995 wrote-off its remaining investment of
approximately $.4 million to reflect management's estimate of the permanent
decline in the value of the investment. This eliminates SmartEnergy's
investment in Green Technologies. On December 29, 1995, Green Technologies
filed for bankruptcy under Chapter 7.
Note 4
Common Stock
On November 8, 1994, the Company's board of directors (Board) reduced the
quarterly dividend rate from $.355 to $.20. As a result, the annual dividend
of $1.42 was reduced 44% to $.80 effective with the first quarter dividend paid
in February 1995. Also, the Board authorized the purchase of up to 2 million
shares of its outstanding common stock from time to time in open market
transactions. Through December 31, 1995, the Company had purchased 195,100
shares at an average price of $13.42 per share. These transactions are
recorded as treasury stock, at cost, in the Company's Consolidated Balance
Sheet.
No shares of common stock were purchased by the Company subsequent to
December 31, 1995.
Note 5
Redeemable preferred stock
Commencing in 1998, the 8.30% Dividend Series Preferred Stock is
redeemable at par through a mandatory sinking fund in the amount of $1.0
million per annum, and at its option, the Company may redeem at par an
additional non-cumulative $1.0 million per annum.
Note 6
Long-term debt and sinking fund requirements
Based on issues outstanding at December 31, 1995, the aggregate amount of
long-term debt maturities and sinking fund requirements are approximately
$1.0 million, $3.0 million, $20.5 million, $5.5 million and $16.5 million for
the years 1996 through 2000, respectively. Substantially all property and
plant is subject to liens under the First Mortgage Bonds.
Note 7
Financial instruments
The estimated fair values of the Company's financial instruments at
December 31, 1995 and 1994 are as follows (dollars in thousands):
1995 1994
Carrying Fair Carrying Fair
Amount Value Amount Value
Cash and cash equivalents $ 11,962 $ 11,962 $ 7,559 $ 7,559
Short-term debt $ 13,505 $ 13,505 $ 11,511 $ 11,511
Sale of accounts receivable
and unbilled revenues $ 12,000 $ 12,000 $ 12,000 $ 12,000
Redeemable preferred stock $ 20,000 $ 25,168 $ 20,000 $ 18,790
Long-term debt $120,142 $128,939 $124,387 $119,374
The carrying amount for cash and cash equivalents and short-term debt
approximates fair value because of the short maturity of those instruments.
The carrying amount for the sale of accounts receivable and unbilled
revenues approximates fair value because of the short maturity of those
instruments.
The fair value of the Company's redeemable preferred stock and long-term
debt is estimated based on the quoted market prices for the same or similar
issues or on the current rates offered to the Company for debt of the same
remaining maturation.
Anticipated regulatory treatment of any excess or decline in the fair
value relative to the carrying value of the Company's financial instruments, if
they were settled at amounts approximating those above, would result in an
increase or decrease in the Company's rates over a prescribed amortization
period. Accordingly, any settlement would not result in a material impact on
the Company's financial position or results of operations.
The Company has no financial instruments that fall under the guidance of
SFAS No. 119, "Disclosure about Derivative Financial Instruments and Fair Value
of Financial Instruments".
The Company adopted SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities", as of January 1, 1994. SFAS No. 115 addresses the
accounting and reporting for investments in equity securities that have readily
determinable fair values and for all investments in debt securities. The
adoption of SFAS No. 115 had no material impact on the Company's financial
position or results of operations.
Note 8
Accounts receivable
At December 31, 1995 and 1994, a total of $12 million of accounts
receivable and unbilled revenues were sold under an accounts receivable
facility.
Accounts receivable and unbilled revenues that have been sold were
transferred with limited recourse. A pool of assets, varying between 3% to 5%
of the accounts receivable and unbilled revenues sold, are set aside for this
potential recourse liability. Accounts receivable and unbilled revenues are
reflected net of sales of $4.4 million and $7.6 million, respectively,
at December 31, 1995 and $4.2 million and $7.8 million, respectively, at
December 31, 1994.
Accounts receivable are also reflected net of an allowance for
uncollectible accounts of $1.6 million and $1.0 million at December 31, 1995
and 1994, respectively.
Note 9
Short-term debt
Utility
The Company uses committed lines of credit and uncommitted loan facilities
to finance its construction and C&LM programs, on a short-term basis, and for
other corporate purposes. As of December 31, 1995, the Company had
$22.25 million of committed lines of credit and $15.0 million of uncommitted
loan facilities which are normally renewed upon expiration and require annual
fees ranging from zero to .25% of an individual line. Borrowings under these
short-term debt arrangements are at interest rates ranging from less than prime
to the prime rate. The Company had $13.5 million and $11.5 million of
outstanding short-term debt at December 31, 1995 and 1994, respectively, at
average interest rates of 6.59% for 1995 and 5.22% for 1994.
Non-Utility
Catamount maintains an Irrevocable Standby Letter of Credit with a bank to
borrow up to an aggregate amount of $1.2 million to replace its share of cash
in the Appomattox Cogeneration Limited Partnership's Project Debt Service
Reserve Fund. This Letter of Credit is for a one-year term with annual
extensions available and requires fees of 1.5% of credit available. At
December 31, 1995 and 1994, there were no borrowings outstanding under this
Letter of Credit. Catamount believes it will not have to perform under this
agreement.
SmartEnergy maintains a $1.0 million revolving line of credit with a bank
to provide working capital and financing assistance for investment purposes.
SmartEnergy had no outstanding short-term debt at December 31, 1995 and
$846,000 at December 31, 1994. Average interest rates were 9.05% for 1995 and
7.29% for 1994.
Financial obligations of the non-utility wholly owned subsidiaries are
non-recourse to the Company.
Note 10
Pension and postretirement benefits
The Company has a non-contributory trusteed pension plan covering all
employees (union and non-union). Under the terms of the pension plan,
employees are generally eligible for monthly benefit payments upon reaching the
age of 65 with a minimum of five years of service. The Company's funding
policy is to contribute, at least, the statutory minimum to a trust. The
Company is not required by its union contract to contribute to multi-employer
plans.
The projected unit credit actuarial cost method was used to compute net
pension costs and the accumulated and projected benefit obligations. The
following table sets forth the funded status of the pension plan and amounts
recognized in the Company's Balance Sheet and Statement of Income (dollars in
thousands):
December 31
1995 1994 1993
Funded status of the plan
Vested benefit obligation $47,351 $35,869 $35,837
Non-vested benefit obligation 276 312 493
------- ------- -------
Accumulated benefit obligation $47,627 $36,181 $36,330
------- ------- -------
Projected benefit obligation $60,554 $46,669 $49,743
Market value of plan assets (primarily equity
and fixed income securities) 55,443 44,115 46,074
Projected benefit obligation more (less)
than market value of plan assets 5,111 2,554 3,669
Unrecognized net transition assets 1,447 1,608 1,768
Unrecognized prior service costs (2,978) (3,178) (3,568)
Unrecognized net gain 2,270 5,963 1,498
------- ------- -------
Net pension liability 5,850 6,947 3,367
Less regulatory asset for restructuring costs 346 1,974 -
------- ------- -------
Effective accrued pension costs $ 5,504 $ 4,973 $ 3,367
------- ------- -------
Net pension costs include the following components
Service cost $ 1,498 $ 2,065 $ 1,491
Interest cost 4,027 3,694 3,377
Actual return on plan assets (11,230) 515 (6,800)
Net amortization and deferral 7,393 (4,095) 3,391
------- ------- -------
Pension costs 1,688 2,179 1,459
Amortization of regulatory asset 1,628 261 -
------- ------- -------
Effective pension costs 3,316 2,440 1,459
Less amount allocated to other accounts 337 318 276
------- ------- -------
Net pension costs expensed $ 2,979 $ 2,122 $ 1,183
------- ------- -------
Assumptions used in calculating pension cost were as follows:
December 31
1995 1994 1993
Weighted average discount rates 7.00% 8.50% 7.25%
Expected long-term return on assets 9.50% 9.50% 9.75%
Rate of increase in future compensation levels 4.50% 5.00% 4.75%
The Company sponsors a defined benefit postretirement medical plan that
covers all employees who retire with ten years or more of service after age 45.
The Company adopted, on a prospective basis, SFAS No. 106, "Employer's
Accounting for Postretirement Benefits Other Than Pensions" (OPEB) which
requires accrual of the expected costs of such benefits during the employees'
years of service. In 1994, the Company adopted a policy to fund its OPEB
obligation through a Voluntary Employees' Benefit Association and 401(h)
Subaccount in its Pension Plan.
The following table sets forth the plan's funded status and amounts
recognized in the Company's Balance Sheet and the amount of expense charged to
the Company's Statement of Income in accordance with SFAS No. 106 (dollars in
thousands):
December 31
1995 1994 1993
Accumulated postretirement benefit obligation
Retirees $(8,207) $(8,265) $(5,098)
Fully eligible active plan participants (600) (521) (1,207)
Other active plan participants (1,033) (806) (1,293)
Plan assets at fair value 1,663 744 -
------- ------- --------
Accumulated postretirement benefit
obligation in excess of plan assets (8,177) (8,848) (7,598)
Unrecognized transition obligation 5,180 5,485 6,253
Unrecognized net loss 428 337 351
------- ------- --------
Accrued postretirement benefit cost (2,569) (3,026) (994)
Regulatory asset for restructuring costs 352 2,008 -
------- ------- --------
Effective accrued postretirement benefit
costs $(2,217) $(1,018) $ (994)
======= ======= =======
Net postretirement benefit cost includes the
following components
Service cost $ 153 $ 194 $ 168
Interest cost 755 682 588
Actual return on plan assets (49) 1 -
Deferral of asset loss during the year (14) (1) -
Amortization of transition obligation over
a twenty-year period 305 305 329
------- ------- --------
Postretirement benefit cost 1,150 1,181 1,085
Amortization of regulatory asset 1,656 265 -
------- ------- --------
Effective postretirement benefit cost 2,806 1,446 1,085
Less amount allocated to other accounts 229 172 205
------- ------- --------
Net postretirement benefit cost expensed $ 2,577 $ 1,274 $ 880
======= ======= =======
Assumptions used in the per capita costs of the accumulated postretirement
benefit obligation were as follows:
December 31
1995 1994 1993
Per capita percent increase in health care costs:
Pre-65 8.00% 9.50% 9.50%
Post-65 6.50% 8.00% 6.00%
Weighted average discount rates 7.00% 8.50% 7.25%
Rate of increase in future compensation levels 4.50% 5.00% 4.75%
Long-term return on assets 8.50% - -
Health care trend rates are assumed to decrease to 5.0% for pre-65 and
4.5% for post-65 for the year 2001 and thereafter.
This decrease results from changes to the retiree medical plan limiting
the cost for employees retiring after 1995 to the 1995 per participant cost.
Increasing the assumed health care cost trend rates by one percentage point in
each year would have resulted in an increase of approximately $691,000 in the
accumulated postretirement benefit obligation as of January 1, 1996, and an
increase of about $51,000 in the aggregate of the service cost and interest
cost components of net periodic postretirement benefit cost for 1995.
Effective January 1, 1994, the Company adopted, on a prospective basis,
SFAS No. 112, "Employers' Accounting for Postemployment Benefits" which
requires accrual of the expected cost of postemployment benefits provided to
former or inactive employees, their beneficiaries, and covered dependents after
employment but before retirement. The Company provides postemployment benefits
consisting of long-term disability benefits, and prior to January 1, 1994
expensed these costs as benefits were paid. For 1993, such costs totaled
$156,000. The accumulated postemployment benefit obligation at January 1, 1996
of approximately $1.1 million is reflected in the accompanying balance sheet as
a deferred postemployment benefit obligation (current and non-current) and is
offset by a corresponding regulatory asset of approximately $.9 million. The
PSB in its October 31, 1994 Rate Order allowed the Company to recover the
regulatory asset over a 7-1/2 year period beginning November 1, 1994 through
April 30, 2002. The postemployment benefit cost charged to expense in 1994 was
approximately $324,000 (pre-tax). Beginning in 1995, the Company paid premiums
to insure the salary continuation portion of future long-term disability
obligations. The post-employment benefit cost charged to expense in 1995,
including insurance premiums, was $100,000 (pre-tax).
In the first quarter of 1994, the Company offered and recorded an
obligation related to a Voluntary Retirement Program (VRP). The VRP was
accepted by 42 employees. The estimated benefit obligation for the VRP as of
December 31, 1995 is about $3.3 million. This amount consists of pension
benefits and postretirement medical benefits of $1.8 million and $1.5 million,
respectively. Additionally, 32 employees accepted a Voluntary Severance
Program (VSP) offered by the Company. Eligible employees had until April 22,
1994 to apply. The Company also announced a layoff of 20 employees on May 9,
1994. VSP and layoff obligations of $.8 million and $.2 million, respectively,
were recorded in the second quarter of 1994. The VRP, VSP and layoff combined
with attrition since mid-1993, yields a total work force reduction of
approximately 14%. In January 1996, the PSB issued an Accounting Order
authorizing the Company to effectively cap its Vermont retail after-tax return
on equity at 10.75% and reduce, in 1995, deferred restructuring costs through
operating expense recognition of approximately $2.9 million. On an after tax
basis, these costs represent a reduction of earnings of approximately
$1.7 million or $.15 per common share. The reduction of these additional
restructuring costs will reduce future annual amortization expense by
approximately $.8 million through May 1999. These restructuring costs were
deferred pursuant to a PSB Accounting Order dated March 11, 1994. The
unamortized balance of these costs was approximately $.8 million at
December 31, 1995, which will be amortized over a 41-month period beginning
January 1, 1996.
Note 11
Income taxes
The components of Federal and state income tax expense are as follows
(dollars in thousands):
Year Ended December 31
1995 1994 1993
Federal:
Current $ 6,703 $ 6,177 $ 2,751
Deferred 2,610 3,417 7,893
Investment tax credits, net (391) (391) (391)
------- ------- -------
8,922 9,203 10,253
State:
Current 1,498 1,710 406
Deferred 488 496 2,113
------- ------- -------
1,986 2,206 2,519
------- ------- -------
Total Federal and state income taxes $10,908 $11,409 $12,772
======= ======= =======
Federal and state income taxes charged (credited) to:
Operating expenses $10,662 $11,934 $12,496
Other income 246 (525) 276
------- ------- -------
$10,908 $11,409 $12,772
======= ======= =======
The principal items comprising the difference between the total income tax
expense and the amount calculated by applying the statutory Federal income tax
rate to income before tax are as follows (dollars in thousands):
Year Ended December 31
1995 1994 1993
Income before income tax $30,759 $26,209 $34,064
Federal statutory rate 35% 35% 35%
Federal statutory tax expense $10,766 $ 9,173 $11,922
Increases (reductions) in taxes resulting
from:
Disallowed regulatory tax asset - 1,641 -
Dividend received deduction (903) (854) (995)
Deferred taxes on plant 324 523 523
State income taxes net of Federal tax
benefit 1,291 1,434 1,637
Investment credit amortization (391) (391) (391)
Seabrook project 22 76 139
Book-to-return adjustments and other (201) (193) (63)
------- ------- -------
Total income tax expense provided $10,908 $11,409 $12,772
======= ======= =======
The tax effects of temporary differences and tax carry forwards that give
rise to significant portions of the deferred tax assets and deferred tax
liabilities are presented below (dollars in thousands):
Year Ended December 31
1995 1994 1993
Deferred tax assets
Alternative minimum tax credit carry
forward $ 203 $ 900 $ 1,400
Non-deductible accruals and other 4,887 4,682 4,186
Deferred compensation and pension 3,546 4,651 4,058
Environmental costs accrual 2,205 2,335 2,142
------- ------- -------
Total deferred tax assets 10,841 12,568 11,786
------- ------- -------
Deferred tax liabilities
Property, plant and equipment 45,670 41,609 38,304
Net regulatory asset 9,084 12,217 13,806
Conservation and load management
expenditures 8,211 7,664 5,123
Nuclear refueling costs 1,782 473 2,633
Other 3,285 3,315 3,948
------- ------- -------
Total deferred tax liabilities 68,032 65,278 63,814
------- ------- -------
Net deferred tax liability $57,191 $52,710 $52,028
======= ======= =======
As a result of adopting SFAS No. 109 in 1993, the Company recognized
additional net accumulated deferred income tax liabilities of approximately
$15 million and a net corresponding regulatory asset from customers of
approximately $15 million for future revenues that will be received when the
temporary differences reverse and are settled in rates. As a result of the
October 31, 1994 PSB Rate Order, during the fourth quarter of 1994, the Company
recognized an additional $1.6 million of tax expense related primarily to a
previous revenue agent review which were expected to be collected from
customers through rates.
A valuation allowance has not been recorded, as the Company expects all
deferred income tax assets will be utilized in the future.
The Company has an alternative minimum tax credit carry forward of
$.2 million which is available to reduce future regular income taxes over an
indefinite period.
Note 12
Retail Rates
The Company filed for a 14.6% or $31.0 million general rate increase on
October 17, 1995 to become effective July 1, 1996, to offset the increasing
cost of providing service. Approximately $29.0 million or 93.5% of the rate
increase request is to recover increased purchased power costs. The filing was
unanimously supported by the Company's board of directors. Five individuals or
entities asked the PSB for permission to intervene in the proceeding. The
request of four of them, including Killington, Ltd. (Killington) was ultimately
granted by the PSB.
On February 13, 1996 the Company reached an agreement with the Vermont
Department of Public Service regarding this rate increase request. Under terms
of the agreement, the Company would increase rates 5.5% June 1, 1996 and 2%
January 1, 1997. The agreement effectively caps the Company's allowed return
on common equity in its Vermont retail business for 1996 and 1997 at 11% by
requiring the Company to reduce deferred C&LM costs to the extent its Vermont
retail return on common equity would otherwise exceed 11%. In addition, the
agreement would remove the penalties imposed in a PSB rate order dated October
31, 1994 discussed below. The agreement is subject to PSB approval.
The Company does not believe that Killington's intervention is of itself
an action that is adverse to the Company's interests, and the Company does not
know at this time whether Killington's intervention will result in its taking
any action or legal positions adverse to the Company and if so whether such
action or legal positions would be considered material to the Company.
Killington is a wholly owned subsidiary of S-K-I, Ltd. (S-K-I), a publicly
held holding company. Killington owns and operates the Killington Ski Area and
is one of the Company's largest customers. Preston Leete Smith, a director of
the Company since 1977, is S-K-I's chief executive officer and chairman of its
executive committee. He is also chairman of the board of directors of
Killington. Mr. Smith has informed the Company that because he recuses himself
from all matters concerning Killington's relationship with the Company, he
learned of Killington's request to intervene after the fact and as a matter of
policy continues to recuse himself from all discussions related to the
intervention, as well as other matters related to Killington's relationship
with the Company. Similarly, as a matter of policy, Mr. Smith would recuse
himself from consideration of any matters by the Company involving Killington
or S-K-I.
A PSB Rate Order dated October 31, 1994, subsequently amended, allowed the
Company a base retail rate increase of 5.07% or approximately $10.2 million.
The PSB Rate Order also lowered the allowed rate of return on the Company's
common stock equity from 12% to 10%. The allowed return on equity is after
deducting two concurrent .75% penalties based on the PSB's conclusions that
there had been "mismanagement of power supply options" and because of "the
Company's failed efforts to acquire all cost-effective energy efficiency
resources". The Company disagrees with the PSB's conclusion.
Note 13
Commitments and contingencies
The Company's power supply is acquired from a number of sources including
its own generating units, jointly owned units, long-term contracts and
short-term purchases from a variety of sources. The cost of power obtained
from sources other than wholly and jointly owned units, including payments
required to be made whether or not energy is received by the Company, is
reflected as Purchased power in the Consolidated Statement of Income.
Through its investments in four nuclear generating companies, the Company
is entitled to receive power from those nuclear units. See Note 2 for a
discussion of the Company's obligations related to its investment in nuclear
generating companies. The Company is also a joint owner of the Millstone #3
nuclear generating plant.
Through Velco, the Company purchases power from a coal-fired generating
plant owned by Northeast Utilities (NU) under a thirty-year contract which
expires April 30, 1998. Under this contract the Company is obligated to make
capacity payments which amounted to approximately $3.8 million, $4.3 million
and $4.2 million for 1993 through 1995, respectively. These capacity payments
will vary over the contract period due to factors such as changes in NU's net
investment, allowed rate of return and operating and maintenance costs.
The Company purchases power from several small power producers who own
qualifying facilities under the Public Utility Regulatory Policies Act of 1978.
These qualifying facilities produce energy using hydroelectric, wood, biomass,
and refuse-burning generation. Under these long-term contracts, in 1995, the
Company purchased 190,105 MWH of which approximately 135,504 MWH is associated
with the Vermont Power Exchange and 37,822 MWH with the New Hampshire/Vermont
Solid Waste Plant owned by Wheelabrator Claremont Company, L.P. The Company
expects to purchase approximately 199,000 MWH of small power output in each
year 1996 through 2000. Based on the forecast level of production, the total
commitment in the next five years to purchase power from these qualifying
facilities is estimated to be $107 million.
The Company will receive varying amounts of capacity and energy from
Hydro-Quebec under the Vermont Joint Owners (VJO) contract during the 1996 to
2016 period. A contract between the state of Vermont and Hydro-Quebec
terminated on September 22, 1995. Related contracts were negotiated between the
Company and Hydro-Quebec which in effect alter the terms and conditions
contained in the VJO contract, reducing the overall power requirements and cost
of the original contract.
The maximum net amount of capacity that the Company will purchase during
the term of the agreements is 143 MW. The total commitment in the next five
years to purchase power under these contracts is approximately $346 million,
less approximately $98 million of power sellbacks, yielding a net cost of
approximately $248 million. The Company recently reached an agreement with
Hydro-Quebec that will lower our 1997 cost of power by approximately
$5.8 million. As part of this agreement, the Company will deliver to NEPOOL
under existing firm energy contracts or joint marketing activities 54 MW of
Phase II transmission capacity for a five- year period beginning July 1, 1996
through June 30, 2001. In addition, the agreement provides for continuing
negotiations with Hydro-Quebec to further reduce future power cost increases.
In the early phase of the VJO contract, two sellback contracts were
negotiated, the first delaying the purchase of about 24 MW of capacity and
associated energy, the second reducing the net purchase of Hydro-Quebec power.
In 1994, the Company negotiated a third sellback arrangement whereby the
Company receives an effective discount on up to 70 MW of capacity starting in
November 1995 for the 1996 contract year (declining to 30 MW in the 1999
contract year). In exchange for this sellback, Hydro-Quebec has the right to
reduce capacity deliveries by up to 50 MW beginning as early as 2004 until
2015, including the use of a like amount of the Company's Phase I/II facility
rights and the ability to reduce the amounts of energy delivered during a
five-year term beginning in 2000.
Joint-ownership The Company's ownership interests in jointly owned generating
and transmission facilities are set forth in the table that follows and
recorded in the Company's Consolidated Balance Sheet (dollars in thousands):
Fuel In Service MW December 31
Type Ownership Date Entitlement 1995 1994
Generating plants:
Wyman #4 Oil 1.78% 1978 11 $ 3,340 $ 3,338
Joseph C. McNeil Various 20.00% 1984 11 14,931 14,871
Millstone #3 Nuclear 1.73% 1986 20 75,380 75,101
Highgate transmission
facility 46.08% 1985 12,786 12,775
-------- --------
106,437 106,085
Accumulated depreciation 28,824 25,683
-------- --------
$ 77,613 $ 80,402
======== ========
The Company's share of operating expenses for these facilities is included
in the corresponding operating accounts on the Consolidated Statement of
Income. Each participant in these facilities must provide for its own
financing.
The Company is responsible for paying its ownership percentage of
decommissioning costs for Millstone #3. Based on a 1992 study, total estimated
obligation at December 31, 1995 was approximately $477.9 million and the funded
obligation was about $92.8 million. The Company's share for the total
obligation and funded obligation was approximately $8.3 million and $1.4
million, respectively.
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 conforms, in all material
respects, with all environmental laws.
Company operations occasionally result in unavoidable and inadvertent
spills or releases of regulated substances or materials, such as the rupture of
a pole mounted transformer, broken hydraulic line, or other similar
occurrences. When the Company learns of such spills and releases from ongoing
operations, they are cleaned up to meet 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 will likely 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. The Company has established a process for determining
whether insurance proceeds are available to offset the costs associated with
these sites.
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 to
determine the magnitude and extent of the contamination. 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. In 1995, a final risk assessment report was completed and submitted to
the state for review. The Company was formally contacted by the EPA in January
1995 asking for written consent to conduct a site evaluation of the Cleveland
Avenue property. The Company does not believe the EPA's evaluation changes its
potential liability so long as reasonable further progress is made in
remediating the site. Following state review, various remediation alternatives
will be investigated. The Company has selected a consulting/engineering firm
to develop and implement a remediation plan for the site and to collect
additional data during 1996.
PCB, Inc. In August 1995, the Company received an Information Request from the
EPA pursuant to a Superfund investigation of two related sites, one in the
state of Kansas and the other in the state of Missouri (Sites). During the
mid-1980's, these Sites received materials containing PCBs from hundreds of
sources, including the Company. The Company has complied with the information
request and will monitor EPA activities at the Sites. At this time, there has
been no estimate of the cost to remediate the Sites. Therefore, the Company
cannot predict whether the Sites represent the potential for a material adverse
effect on its financial condition or results of operations. However, given the
fact EPA has identified more than 1,000 Potentially Responsible Parties (PRPs),
and, based on information currently available to the Company, that the
contaminated Sites and contamination at the Sites appears to be limited to
several buildings, the Company's liability with respect to the Sites is not
expected to be significant.
The Company faces potential liability arising from the alleged disposal of
hazardous materials at three former municipal landfills: the Bennington
Landfill, the Parker Landfill, and the Trafton-Hoisington Landfill.
Bennington Landfill The Bennington Landfill is a Superfund site located in
Bennington, Vermont. An investigation by the Company suggested that it is
unlikely that it contributed a meaningful amount of hazardous substances, if
any, to the site.
In July 1994, the EPA notified the Company that it had reviewed evidence
which, in its opinion, indicated that the Company may have contributed to the
environmental contamination at the Bennington site but that a full
determination of its potential liability for the site had not been made. EPA,
at that time, designated the Company a potentially interested party (PIP).
Also in July 1994, the EPA notified the PRP Group, the Company and other PIPs
that it was proposing a response action at the site with an estimated total
present worth cost of approximately $9.5 million.
During November 1994, the Company was notified that EPA had information
indicating that the Company was a PRP with regard to the Bennington site. The
EPA letter also requested that the Company participate with other PRPs in the
response action described above and further made a demand against the Company
and other PRPs for reimbursement of approximately $.85 million in costs EPA had
incurred in responding to conditions at the site.
The original PRP Group reformed into a larger group, incorporating
additional PRPs, including the Company, to undertake the remedial response, pay
EPA response expenses and obtain reimbursement for the $3 million it spent on
the Engineering Evaluation/Cost Analysis. The Company determined its interests
would be best served by participating in the larger PRP Group while at the same
time exploring the possibility of a "De Minimis" settlement with the EPA,
either alone or as part of a group, premised on its minimal contribution to the
site.
Negotiations between the PRP Group and the EPA continue. The PRP and EPA
recently reached a tentative agreement. Under the terms of that agreement, and
a related internal allocation, the Company's liability would be less than
$100,000. If a final settlement is not achieved, the Company will continue to
explore its settlement options, individually and as a part of a group of "De
Minimis" parties. If all efforts at settlement fail, the Company will defend
any contribution action brought by the other PRPs or the EPA.
Parker Landfill The Parker Landfill is a Superfund site located in
Lyndonville, Vermont. In 1989, the Company received an information request
from the EPA. An investigation conducted at the time concluded that the
Company occasionally sent general trash to the site, and that said trash did
not include hazardous substances. In May 1994, the Company received a second
EPA request seeking additional information. A renewed investigation by the
Company supported its earlier conclusion that the Company did not send
significant amounts of hazardous substances to the site. In summer of 1994,
EPA announced its proposed preferred remedy for this site with an estimated
total present net worth cost of $28.2 million. At this time, based on the
information available, the Company does not believe that this site represents a
material potential liability. Currently, the Company is considered a PIP for
the site. The Company has complied with the information requests and will
monitor EPA activities at the site.
Trafton-Hoisington Landfill The Trafton-Hoisington Landfill was a municipal
and industrial landfill in the Town of Windsor, Vermont. The site is presently
a state lead site although placement on the National Priorities List remains a
possibility. The State of Vermont has reached an agreement with a small group
of PRPs to conduct a site investigation. The Company was contacted by these
PRPs seeking a contribution toward the cost of the site investigation. The
Company conducted an investigation and concluded that no significant amounts of
hazardous substances were sent to the site. Accordingly, the Company has
advised the PRPs it will not make any contribution towards those expenses.
At this time, the Company does not believe these landfill sites represent
the potential for a material adverse effect on its financial condition or
results of operations but 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 where remediation expenses could be material, nor has the
EPA or other Federal or state agency sought contribution from the Company for
the study or remediation of any such sites.
Dividend restrictions The indentures relating to long-term debt and the
Articles of Association contain certain restrictions on the payment of cash
dividends on capital stock. Under the most restrictive of such provisions,
approximately $58 million of retained earnings was not subject to dividend
restriction at December 31, 1995.
Leases and support agreements The Company participated with other electric
utilities in the construction of the Phase I Hydro-Quebec transmission
facilities in northeastern Vermont, which were completed at a total cost of
approximately $140 million. Under a support agreement relating to the
Company's participation in the facilities, the Company is obligated to pay its
4.42% share of Phase I Hydro-Quebec capital costs over a 20-year recovery
period through and including 2006. The Company also participated in the
construction of Phase II Hydro-Quebec transmission facilities constructed
throughout New England, which were completed at a total cost of approximately
$487 million. Under a similar support agreement, the Company is obligated to
pay its 5.132% share of Phase II Hydro-Quebec capital costs over a 25-year
recovery period through and including 2015. All costs under these support
agreements are recorded as purchased transmission expense in accordance with
the Company's rate-making policies. Future minimum payments will be
approximately $3.0 million for each year from 1996 through 2015 and will
decline thereafter. The Company's shares of the net capital cost of these
facilities, totaling approximately $20.5 million, are classified in the
accompanying Consolidated Balance Sheet as "Utility Plant" and "Long-term Lease
Arrangements" (current and non-current).
Minimum rental commitments of the Company under non-cancelable leases as
of December 31, 1995, are not material. Total rental expense entering into the
determination of net income, consisting principally of vehicle and equipment
rentals, was approximately $3.1 million, $3.3 million and $3.3 million for the
years 1993 through 1995, respectively.
Legal proceeding On December 30, 1994, the Company and its board were named as
defendants in a complaint filed in the United States District Court for the
District of Vermont by three shareholders. The complaint alleges, among other
things, (i) that F. Ray Keyser Jr., Chairman of the Company's board, violated
Section 8 of the Clayton Act, 15 U.S.C. Subchapter 19, which precludes certain
interlocking directorships, (ii) that Mr. Keyser violated his fiduciary duties
to the Company's stockholders by acquiring and operating a series of businesses
in competition with the Company without offering those business opportunities
to the Company, (iii) that the remaining individual defendants violated their
fiduciary duties to the Company's stockholders by failing to analyze, or to
cause management to analyze, diversification into propane and fossil fuels, and
by failing to make the Company an effective competitor of alternative fuel
companies, and (iv) that the Company violated the applicable provision of the
Vermont General Corporation Law by failing to provide a list of the Company's
stockholders. The complaint seeks an unspecified amount of damages (including
treble damages against Mr. Keyser), attorneys' fees and costs, a list of the
Company's stockholders, and a court order to enjoin the defendants from alleged
continuing violations of the law. Each of the individual defendants and the
Company itself deny the allegations against them and intend to vigorously
defend the complaint. To that end, the Company and its directors submitted a
Motion to Dismiss, which was argued before the Court on November 29, 1995.
Action on this Motion to Dismiss is pending.
In response to a shareholder letter received in November 1994, the
Company's Board formed a Special Investigation Committee (the Committee),
comprised of three outside directors, to investigate the shareholder's
allegations concerning management's judgment in deciding, in August 1991, to
commit, as part of a consortium of Vermont utilities, to a long-term purchase
of a large amount of hydro-electric power from Hydro-Quebec. The shareholder
also alleged that the Company misled the PSB, prior to the Company's decision
to commit to the purchase, concerning the status of negotiations relating to
the purchase. The Committee hired outside counsel to aid in the investigation
and to render legal advice to it and the Board. At the conclusion of its
investigation, the Committee recommended to the outside members of the full
Board that pursuit of any legal claims implicated by the shareholder's letter
would not be in the best interests of the Company and its shareholders and that
the Company should take no further action with respect to the shareholder's
letter. At the Board's regularly scheduled meeting in September 1995, the
outside directors of the Board voted unanimously to adopt the Committee's
recommendations.
Note 14
New Accounting Pronouncements
In March 1995, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of,"
effective for fiscal years beginning after December 15, 1995. SFAS No. 121
establishes accounting standards for the impairment of long-lived assets and
requires that regulatory assets which are no longer probable of recovery
through future revenues be charged to earnings. The Company adopted SFAS No.
121 on January 1, 1996, and based on the current regulatory rate-making
process, the adoption of SFAS No 121 did not have a material impact on the
Company's financial position or results of operations.
In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation," effective for fiscal years beginning after December 15, 1995.
SFAS No. 123 requires that financial statements include certain disclosures
related to stock-based employee compensation arrangements regardless of the
method used to account for them. The Company does not plan to adopt the
accounting under this pronouncement but rather adopt the required audited pro
forma disclosure. Based on arrangements used by the pronouncement, the pro
forma effects on earnings and earnings per common share are not expected to be
material.
Note 15
Non-recurring Charge
During the fourth quarter of 1994, the Company wrote-off approximately
$2.9 million of costs associated with its proposed new headquarters office
building which reduced after tax earnings by approximately $1.7 million.
Note 16
Unaudited quarterly financial information
The following quarterly financial information is unaudited and includes
all adjustments consisting of normal recurring accruals which are, in the
opinion of management, necessary for a fair statement of results of operations
for such periods. Variations between quarters reflect the seasonal nature of
the Company's business (dollars in thousands, except per share amounts):
Quarter Ended 12 Months
March June September December Ended
1995
Operating revenues $86,863 $62,846 $60,314 $78,254 $288,277
Operating income $14,928 $ 314 $ 1,922 $ 7,073 $ 24,237
Net income (loss) $13,796 $(1,063) $ 1,748 $ 5,370 $ 19,851
Earnings (loss) per share
of common stock $1.13 $(.13) $ .11 $ .42 $1.53
1994
Operating revenues $83,885 $57,684 $59,027 $76,562 $277,158
Operating income (loss) $14,367 $ (447) $ 368 $ 6,815 $ 21,103
Net income (loss) $12,608 $(2,003) $ (791) $ 4,986 $ 14,800
Earnings (loss) per share
of common stock $1.04 $(.22) $(.11) $.38 $1.08
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure.
None.
PART III
Item 10. Directors and Executive Officers of the Registrant.
The Company's Articles of Incorporation and By-Laws provide for the
division of the Board of Directors into three classes having staggered terms of
office. The directors whose terms will expire at the 1996 Annual Meeting of
Stockholders, consisting of the three nominees listed below, will stand for
re-election to a three-year term expiring in 1999. Mr. Robert P. Bliss, Jr.
will retire from the Board upon expiration of his current term. The directors
have chosen not to fill the vacancy created upon Mr. Bliss' retirement from the
Board and in accordance with the Company's By-Laws, the Board has fixed at nine
(9) the number of directors for the ensuing year.
Proxies will be voted (unless otherwise instructed) in favor of the
election of the three nominees as indicated in the table below. While it is
not anticipated that any of the persons listed will be unable to serve as a
director, then the proxies will vote for such other person or persons as the
present Board of Directors shall determine.
The following table sets forth certain information regarding the three
nominees for director, as well as all directors presently serving on the Board
whose terms will expire after the 1996 Annual Meeting. Except for Mr. Young,
each of the individuals listed in the table has been employed by the firm or
has had the occupation set forth under his or her name for the past five years.
Mr. Young, who was elected President and Chief Executive Officer of the Company
upon the retirement of Mr. Thomas C. Webb in December and appointed to fill Mr.
Webb's seat on the Board of Directors, has held a number of executive positions
with the Company during the past five years. In general, the business
experience of each of these persons during this time was typical of a person
engaged in the principal occupation listed for each.
Director Principal Occupation and
Name and Age Since Business Experience
Nominees whose terms will expire in 1999:
Elizabeth Coleman - 58 1990 President, Bennington College,
Bennington, Vermont
Preston Leete Smith - 65 1977 Chief Executive Officer,
S-K-I Ltd., West Lebanon,
New Hampshire (Ski Business)
Robert H. Young - 48 1995 President and Chief Executive
Officer of the Company; Executive
Vice President and Chief
Operating Officer of the Company
from 1993 to 1995; Senior Vice
President and Chief Financial
Officer of the Company from 1988
to 1993; Vice President and Chief
Financial Officer of the Company
from 1987 to 1988.
Directors whose terms will expire in 1998:
Luther F. Hackett - 62 1979 President, Hackett, Valine &
MacDonald, Inc., Burlington,
Vermont (Insurance Agents)
F. Ray Keyser, Jr. - 68 1980 Chairman of the Board of the
Company; Of Counsel, Keyser,
Crowley, Meub, Layden,
Kulig & Sullivan, P.C.
Rutland, Vermont (Lawyers)
Gordon P. Mills - 59 1980 Chairman, EHV-Weidmann
Industries, Inc.,
St. Johnsbury, Vermont
(Manufacturer of Electric
Transformer Insulation)
Directors whose terms will expire in 1997:
Frederic H. Bertrand - 59 1984 Chairman of the Board and
Chief Executive Officer,
National Life Insurance Co.,
Montpelier, Vermont
Mary Alice McKenzie - 38 1992 President and Chief
Executive Officer, John
McKenzie Packing Co., Inc.,
Burlington, Vermont
(Manufacturer of Meat
Products)
Robert D. Stout - 69 1985 Retired President and
Chief Executive Officer,
Putnam Memorial Health
Corporation, Bennington,
Vermont
Executive Officers of the Registrant:
Name and Age Office Officer Since
Thomas C. Webb, 61 (a) Retired President and Chief
Executive Officer 1985
Robert H. Young, 48 President and Chief
Executive Officer
Effective December 30, 1995 1987
Robert de R. Stein, 46 Senior Vice President-Energy
Resources and External Markets 1988
Francis J. Boyle, 50 Vice President-Finance &
Administration and Principal
Financial Officer 1995
Frederick S. Potter, 50 (a) Vice President-Finance &
Administration and Principal
Financial Officer 1994
Jacquel-Anne Chouinard, 56 (a) Vice President-Human Resources 1986
Thomas J. Hurcomb, 58 Vice President-Marketing and
Public Affairs 1975
Robert G. Kirn, 44 Vice President-Engineering and
Operations 1991
William J. Deehan, 43 Assistant Vice President-Rates
and Economic Analysis 1991
Jonathan W. Booraem, 57 Treasurer 1984
Joseph M. Kraus, 41 Secretary and General Counsel 1987
James M. Pennington, 40 Controller and Principal
Accounting Officer 1993
Mr. Young joined the Company in 1987. Mr. Young was elected Senior Vice
President - Finance and Administration in 1988, and in 1993 was elected
Executive Vice President and Chief Operating Officer. He was elected Director,
President and Chief Executive Officer on December 30, 1995 to succeed Mr. Webb.
Mr. Stein joined the Company in 1988 and was elected Vice President -
Energy Supply Planning and Engineering effective January 1, 1990, and Senior
Vice President - Engineering and Energy Resources in 1993. Mr. Stein assumed
his present position in 1994.
Mr. Boyle joined the Company in October, 1995, as Vice President - Finance
and Administration and Chief Financial Officer. From 1993 to 1995, Mr. Boyle
served as Chief Financial Officer of Westmoreland Coal Company (Westmoreland)
in Philadelphia, Pennsylvania. In November, 1994, Westmoreland and several of
its subsidiaries commenced Chapter 11 proceedings to confirm a so-called
"prepackaged" plan of reorganization under which the court was asked to approve
a sale of assets, the proceeds of which were to be used to satisfy in full
certain maturing obligations of Westmoreland. In December, 1994,
Westmoreland's plan of reorganization was confirmed, the asset sale was
consummated, the obligations in question were paid, and Westmoreland emerged
from Bankruptcy. From 1985 to 1992, Mr. Boyle was Chief Financial Officer of
El Paso Natural Gas Company, El Paso, Texas.
Mr. Hurcomb joined the Company in 1967. He was elected Vice President -
External Affairs in 1975, and Vice President - Marketing and Public Affairs in
1993.
Mr. Kirn joined the Company in 1991 as Vice President - Division
Operations and assumed his present position in 1994. From 1979 to 1991, he was
employed by New York State Electric & Gas Corporation.
Mr. Deehan joined the Company in 1985. Prior to being elected to his
present position in 1991, he served as Director of Rate Administration and
Forecasting.
Mr. Booraem joined the Company in 1969 and was elected to his present
position in 1984.
Mr. Kraus joined the Company in 1981. He was elected Corporate Secretary
and Senior Corporate Counsel in 1987 and Corporate Secretary and General
Counsel effective January 1, 1994.
Mr. Pennington joined the Company in 1989. He was named Director of Taxes
and Plant Accounting in 1990. Mr. Pennington was designated Acting Controller
effective July 19, 1992, and was elected Controller and named Principal
Accounting Officer in 1993.
(a) Thomas C. Webb retired effective December 30, 1995 and Jacquel-Anne
Chouinard retired effective December 31, 1995; and Frederick S.
Potter resigned from the Company effective May 9, 1995.
The term of each officer is for one year or until a successor is elected.
Item 11. Executive Compensation.
The following table sets forth all cash compensation paid or to be paid by
the Company and its subsidiaries, as well as the number of stock option awards
earned during the last three fiscal years by the Company's current and retired
Chief Executive Officer and the four other most highly compensated executive
officers whose salary and bonus for services rendered to the Company and its
subsidiaries in all capacities for 1995 exceeded $100,000.
SUMMARY COMPENSATION TABLE
Long Term
Compensation
Annual Compensation Awards
Securities
Other Underlying
Annual Option/ All Other
Name and Principal Salary Bonus Compensation SARs Compensation
Position (1) Year ($) (2) ($)(3) ($) (4) (#) ($) (5)
A. Robert H. Young 1995 178,423 12,500 - 6,000/0 5,876
President and Chief 1994 153,756 0 - 6,000/0 4,927
Executive Officer 1993 141,769 35,995 - 6,000/0 4,533
B. Robert de R. Stein 1995 124,153 - - 4,500/0 4,874
Senior Vice President- 1994 119,606 0 - 4,500/0 4,873
Energy Resources and 1993 114,677 16,804 - 4,500/0 3,988
External Markets
C. Thomas J. Hurcomb 1995 109,765 - - 3,000/0 5,536
Vice President 1994 104,115 0 - 3,000/0 4,534
Marketing and 1993 98,382 15,606 - 3,000/0 4,996
Public Affairs
D. Robert G. Kirn 1995 108,602 - - 3,000/0 4,554
Vice President - 1994 98,201 0 - 3,000/0 4,264
Engineering and 1993 93,736 15,750 - 3,000/0 3,574
Operations
E. Joseph M. Kraus 1995 102,485 12,500 - 3,000/0 8,820
Corporate Secretary 1994 96,657 0 - 3,000/0 8,551
and General Counsel 1993 78,553 16,612 - 1,500/0 4,791
F. Thomas C. Webb 1995 280,898 12,500 9,584 8,000/0 9,792
Retired President 1994 260,759 0 - 8,000/0 7,946
and Chief Executive 1993 248,755 67,183 - 8,000/0 12,453
Officer
1/ - The principal positions listed were held as of December 31, 1995 by the
executive officers named in the Summary Compensation Table other than Mr. Webb
who retired from employment with the Company effective December 30, 1995.
- Mr. Young was elected Director, President and Chief Executive Officer
effective December 30, 1995. Compensation reported for 1995 includes
compensation received in his position as Executive Vice President and Chief
Operating Officer.
2/ - Includes compensation deferred at the election of all executive officers
named, and directors' retainers and fees earned from VELCO by Mr. Webb.
- Includes compensation for services performed by Mr. Webb for Vermont
Yankee and by Mr. Stein for VELCO for which the Company was reimbursed.
3/ - Includes incentive awards by Catamount, as follows for: A: 1995 -
$12,500, 1993 - $10,000; E: 1995 - $12,500, 1993 - $7,500; F: 1995 - $12,500,
1993 - $10,000.
4/ - Payment of $9,584 for the Federal Insurance Contribution Assessment tax
on the present value of future benefits to be paid on the Supplemental
Retirement Plan.
5/ - The total amounts shown in this column for the last fiscal year are
comprised as follows:
- Company matching contributions to the Employee Savings and Investment
Plan includes for A: $5,525; B: $4,620; C: $4,391; D: $4,341; E: $4,096; F:
$5,994.
- Taxable term cost on executive split-dollar insurance. (An insurance
plan that gives both employer and employee an interest in the policy death
benefit on the employee's life.) for A: $351; B: $254; C: $639; D: $213; E:
$109; F: $2,279.
- Includes accrued above-market interest on deferred compensation for C:
$506 and F: $1,519.
- Pay-in-lieu of taking vacation based on Company policy for employees who
qualify for E: $4,615.
Directors' Compensation.
Directors of CVPS receive an annual retainer of $7,200 and members of the
Executive Committee are paid an additional retainer of $400. The Chairman of
each committee receives an additional $1,600 retainer. Directors are also paid
$520 plus expenses for each directors' meeting attended and $260 for each
committee meeting attended if held on the same day as a meeting of the Board or
held by telephone, and a fee of $520 plus expenses for attendance at each other
meeting of such committee. These fees and retainers represent a reduction of
20% from amounts paid in previous years. The Chairman of the Board does not
receive a salary, however, is paid an annual retainer of $30,000. As President
and Chief Executive Officer, Mr. Young receives no director's retainer or other
fees for serving on the Board or any of its committees or for services
performed for consolidated subsidiary companies.
Certain of the directors have elected to defer receipt of all or a portion
of their fees pursuant to the Company's Deferred Compensation Plan for
Directors, described below under the caption entitled "Deferred Compensation
Plan".
Stock Options.
The following table sets forth stock options granted to the Company's
current and retired Chief Executive Officer and the four other most highly
compensated executive officers during 1995 under the Company's 1988 Stock
Option Plan for Key Employees. Under SEC regulations, companies are required
to project an estimate of appreciation of the underlying shares of stock during
the option term. The Company has chosen the Black-Scholes model formula
approved by the SEC. However, the ultimate value will depend on the market
value of the Company's stock at a future date, which may or may not correspond
to the projections below.
Option/SAR Grants in Last Fiscal Year
Grant Date
Individual Grants Value
Number of % of Total
Securities Options/
Underlying SARs
Options/ Granted to Exercise Grant
SARs Employees Or Base Expira- Date
Granted In Fiscal Price tion Present
Name (#) 1/ Year ($/Sh) Date Value 2/
Robert H. Young 6,000/0 15.8% $13.5625 5/3/05 $10,253
Robert de R. Stein 4,500/0 11.8 13.5625 5/3/05 7,690
Thomas J. Hurcomb 3,000/0 7.9 13.5625 5/3/05 5,127
Robert G. Kirn 3,000/0 7.9 13.5625 5/3/05 5,127
Joseph M. Kraus 3,000/0 7.9 13.5625 5/3/05 5,127
Thomas C. Webb 8,000/0 21.1 13.5625 12/30/98 10,850
1/ A total of 38,000 shares were awarded to all plan participants in 1995.
Stock Options are exercisable in whole or in part from the date of the grant
for a period of ten years and one day but in no event later than three years
after retirement from the Company.
2/ Per Black-Scholes model as certified by an independent consultant. The
assumptions used for the Model are as follows: Volatility-.1776 based on
monthly stock prices for the period of 12/31/92 to 12/31/95; Risk free rate of
return-7.5%; Dividend Yield-6.88% over the period of 12/31/92 to 12/31/95; and
a ten year exercise term. For a three year exercise term, the assumptions used
are as follows for the same periods: Volatility-.1776; Risk free rate of
return-6.9%; and Dividend Yield-6.88%.
The following table sets forth stock options exercised by the Company's
current and retired Chief Executive Officer and the four other most highly
compensated executive officers during 1995, and the number and value of all
unexercised options at year-end. The value of "in-the-money" options refers to
options having an exercise price which is less than the market price of the
Company's Common Stock on December 29, 1995.
OPTION/SAR EXERCISES AND YEAR-END VALUE TABLE
Aggregated Option/SAR Exercises in Last Fiscal Year
and FY-End Option/SAR Value
(a) (b) (c) (d) (e)
Number of
Securities Value of
Underlying Unexercised
Unexercised In-the-Money
Options/SARs Options/SARs
At FY-End (#) At FY-End ($)
Shares Acquired Value Exercisable/ Exercisable/
Name on Exercise (#) Realized($)1/ Unexercisable Unexercisable
- --------------- --------------- ------------- ------------- -------------
Robert H. Young - - 22,500/0 -/-
Robert de R. Stein - - 24,000/0 -/-
Thomas J. Hurcomb - - 21,000/0 -/-
Robert G. Kirn - - 14,250/0 -/-
Joseph M. Kraus - - 7,500/0 -/-
Thomas C. Webb - - 30,000/0 -/-
1/ The dollar values in columns (c) and (e) are calculated by determining
the difference between the fair market value of the securities underlying the
options and the exercise or base price of the options at exercise or fiscal
year end, respectively.
Deferred Compensation Plan.
Employees of the Company who are officers are eligible to defer receipt
of a portion of their compensation pursuant to the Company's Deferred
Compensation Plan (the "Deferred Plan") for Officers. Also, certain of the
directors of the Company have elected to defer receipt of all or a portion of
their fees under a similar plan for directors.
Under the Deferred Plan approved effective January 1, 1990 directors and
officers of the Company may elect to defer over a 5-year period receipt of a
specified amount of compensation or fees otherwise currently payable to them
until retirement at age 65 (age 70 for directors), or until their death,
disability, or resignation. Officers may receive a reduced benefit beginning
at age 60 with 10 years of service. Amounts deferred are not currently
taxable for state and federal income taxes. The benefit is equal to the
compensation deferred plus interest credited by the Company. The Deferred
Plan is a defined contribution program under which the Company recovers any
costs, including the cost of capital, through the proceeds of the supporting
life insurance policies. In addition, if death of a director occurs before
age 70, an additional survivor benefit equal to the annual amount deferred
will be paid to the beneficiary each year for fifteen years. This benefit is
also financed by life insurance proceeds.
Pension Plan.
The Pension Plan of Central Vermont Public Service Corporation and Its
Subsidiaries (the "Pension Plan") is a defined benefit plan which covers
employees, among others, who are officers. The Company pays the full cost of
the Pension Plan.
The table below shows the annual amounts payable under the present
provisions of the Pension Plan as amended through December 31, 1995, based on
Final Average Earnings for various years of service, assuming the employee
would retire at age 65 in 1996.
Assumed
5-Year Final Years of Service
AverageEarnings 15 20 25 30 35
$ 80,000 $18,828 $25,105 $31,381 $37,657 $39,657
100,000 24,078 32,105 40,131 48,157 50,657
120,000 29,328 39,105 48,881 58,657 61,657
140,000 34,578 46,105 57,631 69,157 72,657
150,000 37,203(1) 49,605(1) 62,006(1) 74,407(1) 78,157(1)
190,000 37,203(1) 49,605(1) 62,006(1) 74,407(1) 78,157(1)
230,000 37,203(1) 49,605(1) 62,006(1) 74,407(1) 78,157(1)
250,000 37,203(1) 49,605(1) 62,006(1) 74,407(1) 78,157(1)
280,000 37,203(1) 49,605(1) 62,006(1) 74,407(1) 78,157(1)
300,000 37,203(1) 49,605(1) 62,006(1) 74,407(1) 78,157(1)
________
(1) Internal Revenue Code Section 401(a)(17) limits earnings used to
calculate qualified plan benefits to $150,000 for 1995.
Final Average Earnings is the highest five-year average of consecutive
years' Base Salary as set forth in the Salary column of the Summary
Compensation Table over an employee's career with the Company.
The amounts above are payable for the life of the retiree only, and
would be reduced on an actuarial basis if survivor options were chosen. In
addition, no Social Security offset applies to amounts above.
The credited years of service at December 31, 1995 under the Pension
Plan for the named executive officers in the Summary Compensation Table were
as follows: Mr. Young, 8.6 years; Mr. Stein, 7.7 years; Mr. Kraus, 14.5
years; Mr. Hurcomb, 28 years and Mr. Kirn, 4.8 years. At the time of his
retirement, Mr. Webb had 11 years of service with the Company.
Officers' Insurance and Supplemental Retirement Plan.
The Officers' Insurance and Supplemental Retirement Plan (the "SERP") is
designed to supplement the retirement benefits available to the Company's
officers. The SERP is a part of the Company's overall strategy for
attracting and maintaining top managerial talent in the utility industry.
Under this SERP, the named executive officers in the Summary Compensation
Table are covered, while employed, by life insurance at the following
multiple of salary: Mr. Young, four times; Messrs. Stein, Hurcomb, Kirn and
Kraus, three times.
Under the SERP, each officer is entitled to receive, upon retirement at
age 65, fifteen annual payments in amounts equal to a specified percentage of
the officer's final year's Base Salary. The applicable percentages for the
named executive officers in the Summary Compensation Table are as follows:
Mr. Webb, 44.5%; Mr. Young, 44%; Messrs. Stein, Hurcomb, Kirn, and Kraus,
33%. A reduced benefit is available at age 60 for officers who attain age 55
with ten years of service. Mr. Webb, who retired effective December 30,
1995, will receive an unreduced annual benefit of $120,595 under this SERP
per approval of the Board of Directors. A paid-up life insurance of $100,000
is also provided to vested retirees under this SERP. The SERP is financed
through the Company's acquisition of corporate-owned life insurance.
Shown below is the estimated Company provided benefit payable under the
SERP for the named executive officers in the Summary Compensation Table,
assuming they were to retire at age 65, and based on assumed final base pay
amount:
Assumed Final
Annual Base Pay 33% 44% 44.5%
$ $ $ %
80,000 26,400 35,200 35,600
100,000 33,000 44,000 44,500
120,000 39,600 52,800 53,400
140,000 46,200 61,600 62,300
160,000 52,800 70,400 71,200
180,000 59,400 79,200 80,100
220,000 72,600 96,800 97,900
260,000 85,800 114,400 115,700
280,000 92,400 123,200 124,600
300,000 99,000 132,000 133,500
Predecessor Deferred Compensation Plan.
Between 1986 and 1990, the Company allowed officers to defer receipt of
compensation in return for fifteen annual payments of a defined benefit
amount upon retirement. The Company will pay the difference, if any, between
the defined benefit cost and the accumulated value of deferred compensation.
Mr. Hurcomb, who elected to participate, will receive an estimated
annual Company-provided benefit, payable at age 65 of $13,900. Mr. Webb, who
retired December 30, 1995, receives an annual reduced benefit of $26,100.
Since these benefits do not apply to all of the named executive officers,
they have not been reflected in the foregoing pension table.
Employee Savings and Investment Plan.
Effective January 1, 1985 the Company adopted an Employee Savings and
Investment Plan (the "Plan") (also known as a 401(k) Plan) which provides a
means for eligible employees to accumulate savings and investment income
without payment of current income taxes. Presently any employee of the
Company who has completed at least one year of service, as defined in the
Plan, is eligible to participate (Participant). An eligible employee who
elects to participate in the Plan may authorize the Company to contribute to
the Plan for his or her account between 1% and 15% of their pre-tax base
compensation for each pay period. For 1995, the Plan limits the maximum
annual deferral to $9,240 per Participant. This maximum is adjusted annually
for inflation by the Internal Revenue Service. The Company matches 100% of
the first 4% of the compensation the Participant contributes to the Plan. A
Participant may direct the investment of his or her Plan account among six
funds specified in the Plan and is at all times fully vested in his or her
Plan account. Generally, distribution of employee contributions is deferred
until the Participant's death, disability, retirement or other termination of
employment, except in cases of financial hardship. Matching employer
contributions, however, may be withdrawn by the Participant at any time and
for any reason, provided either the amount withdrawn has been in the Plan for
at least two years or the Participant has been a member of the Plan for at
least 5 years. Such in-service withdrawals are generally subject to ordinary
income tax and an additional 10% tax plus a mandatory 20% rollover tax
withholding effective January 1, 1993. Distribution of Plan benefits may be
in the form of cash, an annuity, or in certain circumstances, Common Stock of
the Company. Amounts voluntarily deferred by the named executive officers
are included in the Salary column of the Summary Compensation Table.
Matching Company contributions credited to the Plan accounts of the named
executive officers during 1995 are set forth in the All Other Compensation
column of the Summary Compensation Table.
Contracts with Management.
The Company has entered into severance compensation agreements with
Messrs. Young, Stein, Hurcomb, Kirn, Kraus and four other executive officers
of the Company. The agreements have a term of five years provision for
renewal. They provide that in the event of termination of employment, or a
significant change in employment status as defined in the agreement, within
three years following a change in control of the Company, Messrs. Young,
Stein, Hurcomb, Kirn, Kraus and one other executive officer will receive
2.999 times and three other executive officers will receive two times their
average annual compensation for the preceding five or fewer years of service
and certain legal fees and expenses incurred as a result of termination of
employment.
The provisions of the agreement do not apply if the executive officer
retires, dies, or is disabled, voluntarily resigns, or is dismissed for
cause. In exchange for agreeing to provide consulting services as requested
by the Company for one year and refraining from working in competition with,
or for a competitor of the Company for three years, the agreement permits
continued participation in and retention of benefits under the Deferred
Compensation Plan, Officers' Insurance and Supplemental Retirement Plans, and
health and disability plans. The extent of these provisions depends on an
individual's participation and circumstances, and is specified in each
agreement. The officers with less than 10 years of service would receive a
payment actuarially equivalent to benefits received under the Company's
Pension Plan at age 65 with ten years of service, less any benefit paid under
the Pension Plan. The agreements also provide for the payment to executive
officers of an amount sufficient to offset any federal excise tax on the
termination payments under Section 4999 of the Internal Revenue Code.
Non-qualified stock options not immediately exercisable will become
exercisable in the event of a change of control of the Company as defined in
the Plan.
A change of control occurs under the agreement when (1) any person,
corporation, partnership or group acquires 20% or more of the combined voting
power of the Company's outstanding securities; (2) if those members
constituting a majority of the directors at any given date no longer
constitute a majority of the directors at the end of a period of two
consecutive years thereafter (unless the nomination of each new director was
approved by a vote of at least two-thirds of the directors in office who were
directors at the beginning of the period); or (3) if a third party acquires
ownership or voting power of 10% or more of the outstanding voting securities
of the Company, and subsequently is a "public utility holding company" within
the meaning of the Public Utility Holding Company Act of 1935, or the
Company loses its exemption from or is required to register under that Act.
The Company entered into an agreement with Mr. Webb for consulting
services rendered to the Company after his retirement for 1996 and 1997 to
provide for an orderly management succession and for his continued service on
the Vermont Yankee Board of Directors. The amount to be paid will be $75,000
per year if all contractual arrangements are met.
During 1989, the Board also approved a severance plan in the event of a
change of control for key managers of the Company not covered by the above
plan. In the event of a change in control as described above and a
subsequent discharge from employment within eighteen months for reason other
than cause, certain managers will receive a severance payment equal to one
year's base salary, outplacement services, and coverage under the Company's
medical plan for one year at Company expense. Currently, eighteen managers
are subject to the Plan.
The Board of Directors believes that such agreements protect the
stockholders by ensuring officers and key managers can and will act in
stockholders' best interests without regard to personal situations or
concerns. The Board also believes that such agreements will better ensure
retention and recruitment of high caliber officers and key managers.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The following table sets forth the number of shares of Common Stock of
the Company beneficially owned by each director and nominee director, each of
the executive officers named in the Summary Compensation Table and by all the
directors, nominee directors and executive officers as a group as of January
31, 1996.
Shares of Common Stock Percent
Name Beneficially Owned (1)(2)(3)(4) of Class
Frederic H. Bertrand 11,278 (5)
Elizabeth Coleman 6,850
Luther F. Hackett 12,432 (6)
Thomas J. Hurcomb 23,928
F. Ray Keyser, Jr. 15,062 (7)
Robert G. Kirn 14,468
Joseph M. Kraus 8,765
Mary Alice McKenzie 8,602 (8)
Gordon P. Mills 42,856 (9)
Preston Leete Smith 10,549
Robert de R. Stein 24,349
Robert D. Stout 13,780
Thomas C. Webb 44,129
Robert H. Young 23,195 (10)
All directors and executive
officers as a group (19) 280,579 2.4%
No director, nominee for director or executive officer owns any shares
of the various classes of the Company's outstanding non-voting preferred
stock.
(1) No director, nominee for director or executive officer owns beneficially
in excess of 1% of CVPS' outstanding Common Stock. Except as otherwise
indicated in the footnotes to the table, each of the named individual
possesses sole voting and investment power over the shares listed.
(2) Includes shares that the named individuals have a right to acquire
pursuant to options granted under the 1988 and 1993 Stock Option Plans for
Non-Employee Directors as follows: Messrs. Bertrand, Keyser, Mills and
Stout, 9,750 shares; Ms. McKenzie and Mr. Smith, 8,250 shares; Ms. Coleman
and Mr. Hackett, 6,750 shares.
(3) Includes shares that the named executive officers have a right to
acquire pursuant to options granted under the 1988 Stock Option Plan for Key
Employees as follows: Mr. Hurcomb, 21,000 shares; Mr. Kirn, 14,250 shares;
Mr. Kraus, 7,500 shares; Mr. Stein, 24,000 shares; Mr. Webb, 30,000 shares;
Mr. Young, 22,500 shares; and all executive officers as a group, 159,170
shares.
(4) Includes shares that the named executive officers hold indirectly under
the Company's Employee Savings and Investment and Employee Stock Ownership
Plans as follows: Mr. Hurcomb, 2,913 shares; Mr. Kraus, 102 shares; Mr.
Webb, 9,628 shares; and Mr. Young, 339 shares.
(5) Includes 1,528 shares held jointly with his wife over which Mr. Bertrand
has voting and investment power.
(6) Includes 3,000 shares owned by corporations over which Mr. Hackett has
voting and investment power.
(7) Includes 1,562 shares held jointly with his wife and 3,750 shares held
in a Keogh Trust over which Mr. Keyser has voting and investment power.
(8) Includes 150 shares held jointly with her husband over which Ms.
McKenzie has voting and investment power.
(9) Includes 15,000 shares held in a pension trust over which Mr. Mills has
voting and investment power.
(10) Includes one share held by Mr. Young's wife as custodian for his son
over which Mr. Young disclaims beneficial ownership.
The Company knows of no person, entity or group (within the meaning of
Section 13(d)(3) of the Securities Exchange Act of 1934) which owns
beneficially more than 5% of any class of the Company's outstanding equity
securities.
Reports of Beneficial Ownsership.
Section 16(a) of the Securities Exchange Act of 1934 requires the
Company's directors and executive officers to file reports of ownership and
changes in ownership of Company securities with the SEC and to furnish the
Company with copies of all such reports. It also requires directors,
officers and persons who beneficially own more than ten percent (10%) of the
Company's stock to file initial reports of ownership and subsequent reports
of changes in ownership with the SEC and the NYSE. In making this statement,
the Company has relied on copies of reports that have been filed with the
Commission.
In 1995, Mr. Robert H. Young inadvertently failed to file with the SEC
on a timely basis a Form 4 report involving the sale of 250 shares of Common
Stock of the Company which he beneficially owns. Except for the foregoing,
based solely on a review of the copies of such reports prepared and filed
with the Commission during 1995 by the Company's executive officers and
directors, and on written representations that no other reports were
required, the Company believes its directors and executive officers have
complied with all Section 16(a) filing requirements. The Company does not
have a ten percent holder.
REPORT OF THE COMPENSATION COMMITTEE OF CENTRAL VERMONT PUBLIC SERVICE
CORPORATION
Executive Compensation.
The philosophy of the Compensation Committee (Committee), with regard to
executive compensation, is to maintain a total compensation pay package
which, by virtue of its design and target levels, enables the Company to
recruit the best talent for our jobs, to retain high performing employees by
strongly rewarding exceptional performance, to encourage employees to develop
their skills and abilities; and encourages and supports performance and
decisions that strengthen the Company financially and strategically,
including service to the customer.
Base Annual Salary.
It is the policy of the Committee to establish salaries within a range
that surrounds the 50th percentile of salaries of similar positions as
reported in the annual Executive Compensation Survey conducted by the Edison
Electric Institute, adjusted to reflect the size of the Company as determined
by revenues.
Within this range the salary is determined based on an evaluation of the
individual's qualifications, experience and performance. Increases are
limited by a merit increase budget pool, which is established annually. The
size of the pool, which is then distributed among executive officers based on
an evaluation of their contribution, is based on published salary management
planning surveys, which report the planned merit increase budgets of other
companies.
Management Incentive Compensation Plans.
The Company's executive officers participate in the core utility
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 reaches or exceeds 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
fully rewards the skills and efforts of the executives.
Participants are designated annually by the Board of Directors. In
1995, eleven executive officers were eligible to participate including the
named executive officers in the Summary Compensation Table.
During 1995 the Compensation Committee restructured the Incentive Plan
as follows:
It established a financial performance threshold, below which no
incentive awards would be paid. The threshold is calibrated against the
allowed return on equity. The degree to which the allowed return on equity
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.
Return on equity. 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.
Operating costs and efficiency. Measures the cost of operating and
maintenance expense expressed as a percent of kilowatt hour sales, as
compared to budgeted expense levels.
Retail customer satisfaction index. Measures service reliability by
compiling the combined number and duration of outages in the current year,
and the result of this calculation must be a 5% reduction as measured against
the previous five-year average.
Individual performance. Based on advice and recommendation from the
Chief Executive Officer for others reporting to him, the Committee evaluates
individual officer performance.
If the maximum payout on all of the standards were to be achieved, the
total award would represent 30% of base salary for the Chief Executive
Officer, 25% of base salary for the Chief Operating Officer, 20% for Senior
Vice Presidents and Vice Presidents, and 15% for designated Assistant
Officers. The amount of the payout, if any, to be awarded under the
Company's Incentive Plan for 1995 has not yet been determined.
Catamount Energy Corporation, a wholly owned subsidiary of the Company,
also has an Incentive Plan for officers of Catamount approved annually by its
Board of Directors. Officers of the Company who are also officers of
Catamount may be granted a discretionary award by the Board based upon the
performance of Catamount and the Board's subjective evaluation of each
officer's individual contribution to that performance.
The amounts paid under the Catamount Incentive Plan were based solely on
the profitable sale of a portion of the Company's interest in the Appomattox
project. Amounts paid under the Catamount Incentive Plan for 1995 are set
forth in the Bonus column of the Summary Compensation Table.
Long-Term Incentives.
The Committee views the Company's long-term Stock Option Plan for Key
Employees (Stock Option Plan), approved by the stockholders, as an important
component in its strategy for attracting and retaining executives of high
caliber and helps to motivate them to increase shareholder value.
The options are granted to executive officers annually by the full Board
on recommendation of the Committee. In 1995, ten of the Company's executive
officers received options including the named executive officers in the
Summary Compensation Table. The number of options is determined by reference
to the annual Edison Electric Institute Executive Compensation Survey, with
data statistically adjusted to reflect company size. This determination is
further validated by calculations made in accordance with the Black-Scholes
option pricing model. All awards are provided by means of non-qualified
stock options which have an exercise price equal to 100% of the Fair Market
Value of the Common Stock of the Company on the date of grant. The options
will have value only if the Company's stock price increases. The Committee's
policy is that the exercise price of stock options should not be amended
after grant, except in the event of a stock dividend, stock split or other
change in corporate structure or capitalization affecting the Company's
Common Stock.
The Stock Option Plan is effective for ten years terminating in 1997.
Any new plan will require stockholder approval.
Stock options are exercisable in whole or in part from the date of grant
for a period of ten years and one day but in no event later than three years
after retirement from the Company. Options granted under the Stock Option
Plan are not transferrable except upon the death of the optionee and during
his or her lifetime are exercisable only by him or her. The options terminate
immediately upon termination of employment for cause or after a specified
period in the case of termination of employment for any other reason.
It is the policy of the Committee not to compensate officers through the
use of perquisites. A car is provided to the Chief Executive Officer and
periodic medical examinations for all officers. There are no other
perquisites provided to any officer.
The Company is eligible for tax deductions for compensation paid to its
officers, as each officer's compensation is less than the one million dollar
pay cap enacted by Congress as part of the Omnibus Budget Reconciliation Act
effective 1994.
The Committee retains the services of an independent expert to advise it
with respect to the extent to which its pay practices are consistent with
prevailing industry standards. With the assistance of its advisor, it
aggressively reviews its plans each year to assure that it competitively pays
and rewards executives to act in the interests of the ratepayers and the
shareholders.
Preston Leete Smith, Chairman
Frederic H. Bertrand
Elizabeth Coleman
F. Ray Keyser, Jr.
Gordon P. Mills
Five-Year-Shareholder Return Comparison.
The Securities and Exchange Commission requires that the Company include
in this proxy statement a line-graph presentation comparing cumulative,
five-year shareholder returns on an indexed basis with the S&P 500 Stock
Index and either a published industry or line-of-business index or an index
of peer companies selected by the Company. The Board of Directors has
selected for its peer group index a stock index compiled by the Edison Electric
Institute (EEI), because the Board feels it is the most comprehensive and
representative in as much as it includes stock performance data for 100
investor-owned electric utility companies.
COMPARISON OF FIVE YEAR CUMULATIVE TOTAL RETURN*
CENTRAL VERMONT, EEI 100 ELECTRICS, S & P 500
Measurement Period CVPS EEI S&P 500
(Fiscal Year Covered)
Measurement Pt-12/31/90 $100 $100 $100
FYE 12/31/91 $136.21 $128.87 $130.34
FYE 12/31/92 $157.85 $138.69 $140.25
FYE 12/31/93 $142.35 $154.11 $154.32
FYE 12/31/94 $100.79 $136.28 $156.42
FYE 12/31/95 $105.93 $178.55 $214.99
Assumes $100 Invested on December 31, 1990
*Total Return Assumes Quarterly Reinvestment of Dividends
Item 13. Certain Relationships and Related Transactions.
Report of Indemnification and Advancement of Expenses.
As described above under the caption "Legal Proceedings" each of the
directors and certain former directors of the Company are named defendants in
the Shareholder Suit. In accordance with Article XI of the Company's By-Laws
and applicable provision of the Vermont Business Corporation ACT (VBCA), the
Company during 1995 advanced funds to pay the cost of such directors defense
of the Shareholder Suit, in the aggregate amount of approximately $367,000.
As required by the Company's By-Laws and the VBCA, each of such directors
have agreed to repay advances made by the Company on his or her behalf if it
is ultimately determined that such director did not meet applicable standards
of conduct. Such standards require that the director have acted in good
faith and in a manner that he or she reasonably believed (as to actions in
his or her official capacity with the Company) was in the Company's best
interests, or (in all other cases) was at least not opposed to the Company's
best interests. The Company intends to continue to advance funds for payment
of the defendants' expenses in the Shareholder Suit to the extent permitted
under the Company's By-Laws and the VBCA.
Compensation Committee Interlocks and Insider Participation.
The Compensation Committee consists of non-employee directors and is
responsible for reviewing and making recommendations to the Board of
Directors concerning the compensation of officers of the Company and certain
subsidiaries. The members of the Compensation Committee are also responsible
for the administration of the Stock Option Plan for Key Employees. During
1995, the Compensation Committee held five meetings.
During 1995, the Compensation Committee of the Board consisted of
Preston Leete Smith, Frederic H. Bertrand, Elizabeth Coleman, F. Ray Keyser,
Jr. and Gordon P. Mills. Thomas C. Webb, retired President and Chief
Executive Officer, served as a member of the Board of Directors of S-K-I
Ltd., its Stock Option Committee and Profit Sharing Retirement Trust
Committee but not on its Executive Committee which generally performs the
functions of a compensation committee. Preston Leete Smith, Chief Executive
Officer of S K I Ltd., serves as a Director of CVPS and as Chairman of its
Compensation Committee.
Each of the members of the Compensation Committee is a named defendant
in the Shareholder Suit. As described above, during 1995 the Company
advanced, and intends to advance during 1996, the cost of the directors'
defense of the Shareholder Suit in accordance with applicable provisions of
the Company's By-Laws and Vermont law. See "Report of Indemnification and
Advancement of Expenses" above.
Filed
Herewith
at Page
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K.
(a)1. The following financial statements for Central
Vermont Public Service Corporation and its
wholly owned subsidiaries are filed as part
of this report: (See Item 8)
1.1 Consolidated Statement of Income, for
each of the three years ended
December 31, 1995
Consolidated Statement of Cash Flows,
for each of the three years ended
December 31, 1995
Consolidated Balance Sheet at December 31,
1995 and 1994
Consolidated Statement of Capitalization
at December 31, 1995 and 1994
Consolidated Statement of Changes in
Common Stock Equity for each of the
three years ended December 31, 1995
Notes to Consolidated Financial Statements
(a)2. Financial Statement Schedules:
2.1 Central Vermont Public Service Corporation and
its wholly owned subsidiaries:
Schedule II - Reserves for each of the
three years ended December 31, 1995
Schedules not included have been omitted because they
are not applicable or the required information is shown
in the financial statements or notes thereto. Separate
financial statements of the Registrant (which is primarily
an operating company) have been omitted since they are
consolidated only with those of totally held subsidiaries.
Separate financial statements of subsidiary companies not
consolidated have been omitted since, if considered in
the aggregate, they would not constitute a significant
subsidiary. Separate financial statements of 50% or less
owned persons for which the investment is accounted for
by the equity method by the Registrant have been omitted
since, if considered in the aggregate, they would not
constitute a significant investment.
(a)3. Exhibits (* denotes filed herewith)
Each document described below is incorporated by reference
to the appropriate exhibit numbers and the Commission file
numbers indicated in parentheses, unless the reference to
the document is marked as follows:
* - Filed herewith.
Exhibit 3 Articles of Incorporation and By-Laws
* 3-1 By-Laws, as amended August 7, 1995. (Exhibit 3-1, Form 10-Q
September 30, 1995, File No. 1-8222)
3-2 Articles of Association, as amended August 11, 1992. (Exhibit 3-2,
1992 10-K, File No. 1-8222)
Exhibit 4 Instruments defining the rights of security holders, including
Indentures
Incorporated herein by reference:
4-1 Mortgage dated October 1, 1929, between the Company and Old
Colony Trust Company, Trustee, securing the Company's First
Mortgage Bonds. (Exhibit B-3, File No. 2-2364)
4-2 Supplemental Indenture dated as of August 1, 1936. (Exhibit B-4,
File No. 2-2364)
4-3 Supplemental Indenture dated as of November 15, 1943.
(Exhibit B-3, File No. 2-5250)
4-4 Supplemental Indenture dated as of December 1, 1943. (Exhibit B-4,
File No. 2-5250)
4-5 Directors' resolutions adopted December 14, 1943, establishing the
Series C Bonds and dealing with other related matters.
(Exhibit B-5, File No. 2-5250)
4-6 Supplemental Indenture dated as of April 1, 1944. (Exhibit B-6,
File No. 2-5466)
4-7 Supplemental Indenture dated as of February 1, 1945. (Exhibit 7.6,
File No. 2-5615) (22-385)
4-8 Directors' resolutions adopted April 9, 1945, establishing
the Series D Bonds and dealing with other matters. (Exhibit 7.8,
File No. 2-5615 (22-385)
4-9 Supplemental Indenture dated as of September 2, 1947.
(Exhibit 7.9, File No. 2-7489)
4-10 Supplemental Indenture dated as of July 15, 1948, and directors'
resolutions establishing the Series E Bonds and dealing with other
matters. (Exhibit 7.10, File No. 2-8388)
4-11 Supplemental Indenture dated as of May 1, 1950, and directors'
resolutions establishing the Series F Bonds and dealing with other
matters. (Exhibit 7.11, File No. 2-8388)
4-12 Supplemental Indenture dated August 1, 1951, and directors'
resolutions, establishing the Series G Bonds and dealing with
other matters. (Exhibit 7.12, File No. 2-9073)
4-13 Supplemental Indenture dated May 1, 1952, and directors'
resolutions, establishing the Series H Bonds and dealing with
other matters. (Exhibit 4.3.13, File No. 2-9613)
4-14 Supplemental Indenture dated as of July 10, 1953. (July, 1953 Form
8-K, File No. 1-8222)
4-15 Supplemental Indenture dated as of June 1, 1954, and directors'
resolutions establishing the Series K Bonds and dealing with other
matters. (Exhibit 4.2.16, File No. 2-10959)
4-16 Supplemental Indenture dated as of February 1, 1957, and
directors' resolutions establishing the Series L Bonds and
dealing with other matters. (Exhibit 4.2.16, File No. 2-13321)
4-17 Supplemental Indenture dated as of March 15, 1960. (March, 1960
Form 8-K, File No. 1-8222)
4-18 Supplemental Indenture dated as of March 1, 1962. (March, 1962
Form 8-K, File No. 1-8222)
4-19 Supplemental Indenture dated as of March 2, 1964. (March, 1964
Form 8-K, File No, 1-8222)
4-20 Supplemental Indenture dated as of March 1, 1965, and directors'
resolutions establishing the Series M Bonds and dealing with other
matters. (April, 1965 Form 8-K, File No. 1-8222)
4-21 Supplemental Indenture dated as of December 1, 1966, and
directors' resolutions establishing the Series N Bonds and
dealing with other matters. (January, 1967 Form 8-K, File
No. 1-8222)
4-22 Supplemental Indenture dated as of December 1, 1967, and
directors' resolutions establishing the Series O Bonds and
dealing with other matters. (December, 1967 Form 8-K, File
No. 1-8222)
4-23 Supplemental Indenture dated as of July 1, 1969, and directors'
resolutions establishing the Series P Bonds and dealing with other
matters. (Exhibit B.23, July, 1969 Form 8-K, File No. 1-8222)
4-24 Supplemental Indenture dated as of December 1, 1969, and
directors' resolutions establishing the Series Q Bonds January,
and dealing with other matters. (Exhibit B.24, January, 1970
Form 8-K, File No. 1-8222)
4-25 Supplemental Indenture dated as of May 15, 1971, and directors'
resolutions establishing the Series R Bonds and dealing with other
matters. (Exhibit B.25, May, 1971, Form 8-K, File No. 1-8222)
4-26 Supplemental Indenture dated as of April 15, 1973, and directors'
resolutions establishing the Series S Bonds and dealing with other
matters. (Exhibit B.26, May, 1973, Form 8-K, File No. 1-8222)
4-27 Supplemental Indenture dated as of April 1, 1975, and directors'
resolutions establishing the Series T Bonds and dealing with other
matters. (Exhibit B.27, April, 1975, Form 8-K, File No. 1-8222)
4-28 Supplemental Indenture dated as of April 1, 1977. (Exhibit 2.42,
File No. 2-58621)
4-29 Supplemental Indenture dated as of July 29, 1977, and directors'
resolutions establishing the Series U, V, W, and X Bonds and
dealing with other matters. (Exhibit 2.43, File No. 2-58621)
4-30 Thirtieth Supplemental Indenture dated as of September 15, 1978,
and directors' resolutions establishing the Series Y Bonds and
dealing with other matters. (Exhibit B-30, 1980 Form 10-K, File
No. 1-8222)
4-31 Thirty-first Supplemental Indenture dated as of September 1, 1979,
and directors' resolutions establishing the Series Z Bonds and
dealing with other matters. (Exhibit B-31, 1980 Form 10-K, File
No. 1-8222)
4-32 Thirty-second Supplemental Indenture dated as of June 1, 1981,
and directors' resolutions establishing the Series AA Bonds and
dealing with other matters. (Exhibit B-32, 1981 Form 10-K, File
No. 1-8222)
4-45 Thirty-third Supplemental Indenture dated as of August 15, 1983,
and directors' resolutions establishing the Series BB Bonds and
dealing with other matters. (Exhibit B-45, 1983 Form 10-K, File
No. 1-8222)
4-46 Bond Purchase Agreement between Merrill, Lynch, Pierce, Fenner &
Smith, Inc., Underwriters and The Industrial Development Authority
of the State of New Hampshire, issuer and Central Vermont Public
Service Corporation. (Exhibit B-46, 1984 Form 10-K, File
No. 1-8222)
4-47 Thirty-Fourth Supplemental Indenture dated as of January 15, 1985,
and directors' resolutions establishing the Series CC Bonds and
Series DD Bonds and matters connected therewith. (Exhibit B-47,
1985 Form 10-K, File No. 1-8222)
4-48 Bond Purchase Agreement among Connecticut Development Authority
and Central Vermont Public Service Corporation with E. F. Hutton
& Company Inc. dated December 11, 1985. (Exhibit B-48, 1985 Form
10-K, File No. 1-8222)
4-49 Stock-Purchase Agreement between Vermont Electric Power
Company, Inc. and the Company dated August 11, 1986 relative
to purchase of Class C Preferred Stock. (Exhibit B-49, 1986
Form 10-K, File No. 1-8222)
4-50 Thirty-Fifth Supplemental Indenture dated as of December 15, 1989
and directors' resolutions establishing the Series EE, Series FF
and Series GG Bonds and matters connected therewith. (Exhibit
4-50, 1989 Form 10-K, File No. 1-8222)
4-51 Thirty-Sixth Supplemental Indenture dated as of December 10, 1990
and directors' resolutions establishing the Series HH Bonds and
matters connected therewith. (Exhibit 4-51, 1990 Form 10-K, File
No. 1-8222)
4-52 Thirty-Seventh Supplemental Indenture dated December 10, 1991 and
directors' resolutions establishing the Series JJ Bonds and
matters connected therewith. (Exhibit 4-52, 1991 Form 10-K, File
No. 1-8222)
4-53 Thirty-Eight Supplemental Indenture dated December 10, 1993
establishing Series KK, LL, MM, NN, OO. (Exhibit 4-53, 1993 Form
10-K, File No. 1-8222)
Exhibit 10 Material Contracts (*Denotes filed herewith)
Incorporated herein by reference:
10.l Copy of firm power Contract dated August 29, 1958, and
supplements thereto dated September 19, 1958, October 7, 1958,
and October 1, 1960, between the Company and the State
of Vermont (the "State"). (Exhibit C-1, File No. 2-17184)
10.1.1 Agreement setting out Supplemental NEPOOL Understandings
dated as of April 2, 1973. (Exhibit C-22, File
No. 5-50198)
10.2 Copy of Transmission Contract dated June 13, 1957, between Velco
and the State, relating to transmission of power. (Exhibit 10.2,
1993 Form 10-K, File No. 1-8222)
10.2.1 Copy of letter agreement dated August 4, 1961, between
Velco and the State. (Exhibit C-3, File No. 2-26485)
10.2.2 Amendment dated September 23, 1969. (Exhibit C-4, File
No. 2-38161)
10.2.3 Amendment dated March 12, 1980. (Exhibit C-92, 1982
Form 10-K, File No. 1-8222)
10.2.4 Amendment dated September 24, 1980. (Exhibit C-93, 1982
Form 10-K, File No. 1-8222)
10.3 Copy of subtransmission contract dated August 29, 1958, between
Velco and the Company (there are seven similar contracts between
Velco and other utilities). (Exhibit 10.3, 1993 Form 10-K,
Form No. 1-8222)
10.3.1 Copies of Amendments dated September 7, 196l, November 2,
1967, March 22, 1968, and October 29, 1968. (Exhibit C-6,
File No. 2-32917)
10.3.2 Amendment dated December 1, 1972. (Exhibit 10.3.2, 1993
Form 10-K, File No. 1-8222)
10.4 Copy of Three-Party Agreement dated September 25, 1957, between
the Company, Green Mountain and Velco. (Exhibit C-7, File
No. 2-17184)
10.4.1 Superseding Three Party Power Agreement dated January 1,
1990. (Exhibit 10-201, 1990 Form 10-K, File No. 1-8222)
10.4.2 Agreement Amending Superseding Three Party Power
Agreement dated May 1, 1991. (Exhibit 10.4.2, 1991 Form
10-K, File No. 1-8222)
10.5 Copy of firm power Contract dated December 29, 1961, between the
Company and the State, relating to purchase of Niagara Project
power. (Exhibit C-8, File No. 2-26485)
10.5.1 Amendment effective as of January 1, 1980. (Exhibit
10.5.1, 1993 Form 10-K, File No. 1-8222)
10.6 Copy of agreement dated July 16, 1966, and letter supplement
dated July 16, 1966, between Velco and Public Service Company of
New Hampshire relating to purchase of single unit power from
Merrimack II. (Exhibit C-9, File No. 2-26485)
10.6.1 Copy of Letter Agreement dated July 10, 1968, modifying
Exhibit A. (Exhibit C-10, File No. 2-32917)
10.7 Copy of Capital Funds Agreement between the Company and Vermont
Yankee dated as of February 1, 1968. (Exhibit C-11, File No.
70-4611)
10.7.1 Copy of Amendment dated March 12, 1968. (Exhibit C-12,
File No. 70-4611)
10.7.2 Copy of Amendment dated September 1, 1993. (Exhibit
10.7.2, 1994 Form 10-K, File No. 1-8222)
10.8 Copy of Power Contract between the Company and Vermont Yankee
dated as of February 1, 1968. (Exhibit C-13, File No. 70-4591)
10.8.1 Amendment dated April 15, 1983. (Exhibit 10.8.1, 1993
Form 10-K, File No. 1-8222)
10.8.2 Copy of Additional Power Contract dated February 1,
1984. (Exhibit C-123, 1984 Form 10-K, File No. 1-8222)
10.8.3 Amendment No. 3 to Vermont Yankee Power Contract,
dated April 24, 1985. (Exhibit 10-144, 1986 Form 10-K,
File No. 1-8222)
10.8.4 Amendment No. 4 to Vermont Yankee Power Contract,
dated June 1, 1985. (Exhibit 10-145, 1986 Form 10-K,
File No. 1-8222)
10.8.5 Amendment No. 5 dated May 6, 1988. (Exhibit 10-179,
1988 Form 10-K, File No. 1-8222)
10.8.6 Amendment No. 6 dated May 6, 1988. (Exhibit 10-180,
1988 Form 10-K, File No. 1-8222)
10.8.7 Amendment No. 7 dated June 15, 1989. (Exhibit 10-195,
1989 Form 10-K, File No. 1-8222)
10.9 Copy of Capital Funds Agreement between the Company and Maine
Yankee dated as of May 20, 1968. (Exhibit C-14, File No. 70-4658)
10.9.1 Amendment No. 1 dated August 1, 1985. (Exhibit C-125,
1984 Form 10-K, File No. 1-8222)
10.10 Copy of Power Contract between the Company and Maine Yankee
dated as of May 20, 1968. (Exhibit C-15, File No. 70-4658)
10.10.1 Amendment No. 1 dated March 1, 1984. (Exhibit C-112,
1984 Form 10-K, File No. 1-8222)
10.10.2 Amendment No. 2 effective January 1, 1984. (Exhibit
C-113, 1984 Form 10-K, File No. 1-8222)
10.10.3 Amendment No. 3 dated October 1, 1984. (Exhibit C-114,
1984 Form 10-K, File No. 1-8222)
10.10.4 Additional Power Contract dated February 1, 1984.
(Exhibit C-126, 1985 Form 10-K, File No. 1-8222)
10.11 Copy of Agreement dated January 17, 1968, between Velco and
Public Service Company of New Hampshire relating to purchase of
additional unit power from Merrimack II. (Exhibit C-16, File
No. 2-32917)
10.12 Copy of Agreement dated February 10, 1968 between the Company
and Velco relating to purchase by Company of Merrimack II unit
power. (There are 25 similar agreements between Velco and
other utilities.) (Exhibit C-17, File No. 2-32917)
10.13 Copy of Three-Party Power Agreement dated as of November 21,
1969, among the Company, Velco, and Green Mountain relating
to purchase and sale of power from Vermont Yankee Nuclear
Power Corporation. (Exhibit C-18, File No. 2-38161)
10.13.1 Amendment dated June 1, 1981. (Exhibit 10.13.1, 1993
Form 10-K, File No. 1-8222)
10.14 Copy of Three-Party Transmission Agreement dated as of
November 21, 1969, among the Company, Velco, and Green Mountain
providing for transmission of power from Vermont Yankee Nuclear
Power Corporation. (Exhibit C-19, File No. 2-38161)
10.14.1 Amendment dated June 1, 1981. (Exhibit 10.14.1, 1993
Form 10-K, File No. 1-8222)
10.15 Copy of Stockholders Agreement dated September 25, 1957,
between the Company, Velco, Green Mountain and Citizens
Utilities Company. (Exhibit No. C-20, File No. 70-3558)
10.16 New England Power Pool Agreement dated as of September 1, 1971,
as amended to November 1, 1975. (Exhibit C-21, File
No. 2-55385)
10.16.1 Amendment dated December 31, 1976. (Exhibit 10.16.1
1993 Form 10-K, File No. 1-8222)
10.16.2 Amendment dated January 23, 1977. (Exhibit 10.16.2,
1993 Form 10-K, File No. 1-8222)
10.16.3 Amendment dated July 1, 1977. (Exhibit 10.16.3, 1993
Form 10-K, File No. 1-8222)
10.16.4 Amendment dated August 1, 1977. (Exhibit 10.16.4,
1993 Form 10-K, File No. 1-8222)
10.16.5 Amendment dated August 15, 1978. (Exhibit 10.16.5,
1993 Form 10-K, File No. 1-8222)
10.16.6 Amendment dated January 31, 1979. (Exhibit 10.16.6,
1993 Form 10-K, File No. 1-8222)
10.16.7 Amendment dated February 1, 1980. (Exhibit 10.16.7,
1993 Form 10-K, File No. 1-8222)
10.16.8 Amendment dated December 31, 1976. (Exhibit 10.16.8,
1993 Form 10-K, File No. 1-8222)
10.16.9 Amendment dated January 31, 1977. (Exhibit 10.16.9,
1993 Form 10-K, File No. 1-8222)
10.16.10 Amendment dated July 1, 1977. (Exhibit 10.16.10, 1993
Form 10-K, File No. 1-8222)
10.16.11 Amendment dated August 1, 1977. (Exhibit 10.16.11,
1993 Form 10-K, File No. 1-8222)
10.16.12 Amendment dated August 15, 1978. (Exhibit 10.16.12,
1993 Form 10-K, File No. 1-8222)
10.16.13 Amendment dated January 31, 1980. (Exhibit 10.16.13,
1993 Form 10-K, File No. 1-8222)
10.16.14 Amendment dated February 1, 1980. (Exhibit 10.16.14,
1993 Form 10-K, File No. 1-8222)
10.16.15 Amendment dated September 1, 1981. (Exhibit 10.16.15,
1993 Form 10-K, File No. 1-8222)
10.16.16 Amendment dated December 1, 1981. (Exhibit 10.16.16,
1993 Form 10-K, File No. 1-8222)
10.16.17 Amendment dated June 15, 1983. (Exhibit 10.16.17,
1993 Form 10-K, File No. 1-8222)
10.16.18 Amendment dated September 1, 1985. (Exhibit 10-160,
1986 Form 10-K, File No. 1-8222)
10.16.19 Amendment dated April 30, 1987. (Exhibit 10-172, 1987
Form 10-K, File No. 1-8222)
10.16.20 Amendment dated March 1, 1988. (Exhibit 10-178, 1988
Form 10-K, File No. 1-8222)
10.16.21 Amendment dated March 15, 1989. (Exhibit 10-194, 1989
Form 10-K, File No. 1-8222)
10.16.22 Amendment dated October 1, 1990. (Exhibit 10-203,
1990 Form 10-K, File No. 1-8222)
10.16.23 Amendment dated September 15, 1992. (Exhibit
10.16.23, 1992 Form 10-K, File No. 1-8222)
10.16.24 Amendment dated May 1, 1993. (Exhibit 10.16.24, 1993
Form 10-K, File No. 1-8222)
10.16.25 Amendment dated June 1, 1993. (Exhibit 10.16.25, 1993
Form 10-K, File No. 1-8222)
10.16.26 Amendment dated June 1, 1994. (Exhibit 10.16.26, 1994
Form 10-K, File No. 1-8222)
* 10.16.27 Thirty-Second Amendment dated September 1, 1995.
(Exhibit 10.16.27, Form 10-Q dated September 30, 1995,
File No. 1-8222)
10.17 Agreement dated October 13, 1972, for Joint Ownership,
Construction and Operation of Pilgrim Unit No. 2 among Boston
Edison Company and other utilities, including the Company.
(Exhibit C-23, File No. 2-45990)
10.17.1 Amendments dated September 20, 1973, and September 15,
1974. (Exhibit C-24, File No. 2-51999)
10.17.2 Amendment dated December 1, 1974. (Exhibit C-25, File
No. 2-54449)
10.17.3 Amendment dated February 15, 1975. (Exhibit C-26,
File No. 2-53819)
10.17.4 Amendment dated April 30, 1975. (Exhibit C-27, File
No. 2-53819)
10.17.5 Amendment dated as of June 30, 1975. (Exhibit C-28,
File No. 2-54449)
10.17.6 Instrument of Transfer dated as of October 1, 1974,
assigning partial interest from the Company to Green
Mountain Power Corporation. (Exhibit C-29, File No.
2-52177)
10.17.7 Instrument of Transfer dated as of January 17, 1975,
assigning a partial interest from the Company to the
Burlington Electric Department. (Exhibit C-30, File
No. 2-55458)
10.17.8 Addendum dated as of October 1, 1974 by which Green
Mountain Power Corporation became a party thereto.
(Exhibit C-31, File No. 2-52177)
10.17.9 Addendum dated as of January 17, 1975 by which the
Burlington Electric Department became a party thereto.
(Exhibit C-32, File No. 2-55450)
10.17.10 Amendment 23 dated as of 1975. (Exhibit C-50, 1975
Form 10-K, File No. 1-8222)
10.18 Agreement for Sharing Costs Associated with Pilgrim Unit No.2
Transmission dated October 13, 1972, among Boston Edison
Company and other utilities including the Company. (Exhibit
C-33, File No. 2-45990)
10.18.1 Addendum dated as of October 1, 1974, by which Green
Mountain Power Corporation became a party thereto.
(Exhibit C-34, File No. 2-52177)
10.18.2 Addendum dated as of January 17, 1975, by which
Burlington Electric Department became a party thereto.
(Exhibit C-35, File No. 2-55458)
10.19 Agreement dated as of May 1, 1973, for Joint Ownership,
Construction and Operation of New Hampshire Nuclear Units among
Public Service Company of New Hampshire and other utilities,
including Velco. (Exhibit C-36, File No. 2-48966)
10.19.1 Amendments dated May 24, 1974, June 21, 1974,
September 25, 1974, October 25, 1974, and January 31,
1975. (Exhibit C-37, File No. 2-53674)
10.19.2 Instrument of Transfer dated September 27, 1974,
assigning partial interest from Velco to the Company.
(Exhibit C-38, File No. 2-52177)
10.19.3 Amendments dated May 24, 1974, June 21, 1974, and
September 25, 1974. (Exhibit C-81, File No. 2-51999)
10.19.4 Amendments dated October 25, 1974 and January 31,
1975. (Exhibit C-82, File No. 2-54646)
10.19.5 Sixth Amendment dated as of April 18, 1979. (Exhibit
C-83, File No. 2-64294)
10.19.6 Seventh Amendment dated as of April 18, 1979.
(Exhibit C-84, File No. 2-64294)
10.19.7 Eighth Amendment dated as of April 25, 1979. (Exhibit
C-85, File No. 2-64815)
10.19.8 Ninth Amendment dated as of June 8, 1979. (Exhibit
C-86, File No. 2-64815)
10.19.9 Tenth Amendment dated as of October 10, 1979.
(Exhibit C-87, File No. 2-66334)
10.19.10 Eleventh Amendment dated as of December 15, 1979.
(Exhibit C-88, File No.2-66492)
10.19.11 Twelfth Amendment dated as of June 16, 1980.
(Exhibit C-89, File No. 2-68168)
10.19.12 Thirteenth Amendment dated as of December 31, 1980.
(Exhibit C-90, File No. 2-70579)
10.19.13 Fourteenth Amendment dated as of June 1, 1982.
(Exhibit C-104, 1982 Form 10-K, File No. 1-8222)
10.19.14 Fifteenth Amendment dated April 27, 1984. (Exhibit
10-134, 1986 Form 10-K, File No. 1-8222)
10.19.15 Sixteenth Amendment dated June 15, 1984. (Exhibit
10-135, 1986 Form 10-K, File No. 1-8222)
10.19.16 Seventeenth Amendment dated March 8, 1985. (Exhibit
10-136, 1986 Form 10-K, File No. 1-8222)
10.19.17 Eighteenth Amendment dated March 14, 1986. (Exhibit
10-137, 1986 Form 10-K, File No. 1-8222)
10.19.18 Nineteenth Amendment dated May 1, 1986. (Exhibit
10-138, 1986 Form 10-K, File No. 1-8222)
10.19.19 Twentieth Amendment dated September 19, 1986.
(Exhibit 10-139, 1986 Form 10-K, File No. 1-8222)
10.19.20 Amendment No. 22 dated January 13, 1989. (Exhibit
10-193, 1989 Form 10-K, File No. 1-8222)
10.20 Transmission Support Agreement dated as of May 1, 1973, among
Public Service Company of New Hampshire and other utilities,
including Velco, with respect to New Hampshire Nuclear Units.
(Exhibit C-39, File No. 2-48966)
10.21 Sharing Agreement - 1979 Connecticut Nuclear Unit dated
September 1, 1973, to which the Company is a party. (Exhibit
C-40, File No. 2-50142)
10.21.1 Amendment dated as of August 1, 1974. (Exhibit C-41,
File No. 2-51999)
10.21.2 Instrument of Transfer dated as of February 28, 1974,
transferring partial interest from the Company to
Green Mountain. (Exhibit C-42, File No. 2-52177)
10.21.3 Instrument of Transfer dated January 17, 1975,
transferring a partial interest from the Company to
Burlington Electric Department. (Exhibit C-43, File
No. 2-55458)
10.21.4 Amendment dated May 11, 1984. (Exhibit C-110, 1984
Form 10-K, File No. 1-8222)
10.22 Preliminary Agreement dated as of July 5, 1974, with respect to
1981 Montague Nuclear Generating Units. (Exhibit C-44, File
No. 2-51733)
10.22.1 Amendment dated June 30, 1975. (Exhibit C-45, File
No. 2-54449)
10.23 Agreement for Joint Ownership, Construction and Operation of
William F. Wyman Unit No. 4 dated November 1, 1974, among
Central Maine Power Company and other utilities including the
Company. (Exhibit C-46, File No. 2-52900)
10.23.1 Amendment dated as of June 30, 1975. (Exhibit C-47,
File No. 2-55458)
10.23.2 Instrument of Transfer dated July 30, 1975, assigning
a partial interest from Velco to the Company.
(Exhibit C-48, File No. 2-55458)
10.24 Transmission Agreement dated November 1, 1974, among Central
Maine Power Company and other utilities including the Company
with respect to William F. Wyman Unit No. 4. (Exhibit C-49,
File No. 2-54449)
10.25 Copy of Power Contract between the Company and Yankee Atomic
dated as of June 30, 1959. (Exhibit C-61, 1981 Form 10-K,
File No. 1-8222)
10.25.1 Revision dated April 1, 1975. (Exhibit C-61, 1981
Form 10-K, File No. 1-8222)
10.25.2 Amendment dated May 6, 1988. (Exhibit 10-181, 1988
Form 10-K, File No. 1-8222)
10.25.3 Amendment dated June 26, 1989. (Exhibit 10-196, 1989
Form 10-K, File No. 1-8222)
10.25.4 Amendment dated July 1, 1989. (Exhibit 10-197, 1989
Form 10-K, File No. 1-8222)
10.25.5 Amendment dated February 1, 1992. (Exhibit 10.25.5,
1992 Form 10-K, File No. 1-8222)
10.26 Copy of Transmission Contract between the Company and Yankee
Atomic dated as of June 30, 1959. (Exhibit C-63, 1981 Form
10-K, File No. 1-8222)
10.27 Copy of Power Contract between the Company and Connecticut
Yankee dated as of June 1, 1964. (Exhibit C-64, 1981 Form
10-K, File No. 1-8222)
10.27.1 Supplementary Power Contract dated March 1, 1978.
(Exhibit C-94, 1982 Form 10-K, File No. 1-8222)
10.27.2 Amendment dated August 22, 1980. (Exhibit C-95,
1982 Form 10-K, File No. 1-8222)
10.27.3 Amendment dated October 15, 1982. (Exhibit C-96,
1982 Form 10-K, File No. 1-8222)
10.27.4 Second Supplementary Power Contract dated April 30,
1984. (Exhibit C-115, 1984 Form 10-K, File No.
1-8222)
10.27.5 Additional Power Contract dated April 30, 1984.
(Exhibit C-116, 1984 Form 10-K, File No. 1-8222)
10.28 Copy of Transmission Contract between the Company and
Connecticut Yankee dated as of July 1, 1964. (Exhibit C-65,
1981 Form 10-K, File No. 1-8222)
10.29 Copy of Capital Funds Agreement between the Company and
Connecticut Yankee dated as of July 1, 1964. (Exhibit C-66,
1981 Form 10-K, File No. 1-8222)
10.29.1 Copy of Capital Funds Agreement between the Company
and Connecticut Yankee dated as of September 1, 1964.
(Exhibit C-67, 1981 Form 10-K, File No. 1-8222)
10.30 Copy of Five-Year Capital Contribution Agreement between the
Company and Connecticut Yankee dated as of November 1, 1980.
(Exhibit C-68, 1981 Form 10-K, File No. 1-8222)
10.31 Form of Guarantee Agreement dated as of November 7, 1981, among
certain banks, Connecticut Yankee and the Company, relating to
revolving credit notes of Connecticut Yankee. (Exhibit C-69,
1981 Form 10-K, File No. 1-8222)
10.32 Form of Guarantee Agreement dated as of November 13, 1981,
between The Connecticut Bank and Trust Company, as Trustee, and
the Company, relating to debentures of Connecticut Yankee.
(Exhibit C-70, 1981 Form 10-K, File No. 1-8222)
10.33 Form of Guarantee Agreement dated as of November 5, 1981,
between Bankers Trust Company, as Trustee of the Vernon Energy
Trust, and the Company, relating to Vermont Yankee Nuclear Fuel
Sale Agreement. (Exhibit C-71, 1981 Form 10-K, File No. 1-8222)
10.34 Preliminary Vermont Support Agreement re Quebec Interconnection
between Velco and among seventeen Vermont Utilities dated
May 1, 1981. (Exhibit C-97, 1982 Form 10-K, File No. 1-8222)
10.34.1 Amendment dated June 1, 1982. (Exhibit C-98, 1982
Form 10-K, File No. 1-8222)
10.35 Vermont Participation Agreement for Quebec Interconnection
between Velco and among seventeen Vermont Utilities dated
July 15, 1982. (Exhibit C-99, 1982 Form 10-K, File No. 1-8222)
10.35.1 Amendment No. 1 dated January 1, 1986. (Exhibit C-132,
1986 Form 10-K, File No. 1-8222)
10.36 Vermont Electric Transmission Company Capital Funds Support
Agreement between Velco and among sixteen Vermont Utilities
dated July 15, 1982. (Exhibit C-100, 1982 Form 10-K, File No.
1-8222)
10.37 Vermont Transmission Line Support Agreement, Vermont Electric
Transmission Company and twenty New England Utilities dated
December 1, 1981, as amended by Amendment No. 1 dated June 1,
1982, and by Amendment No. 2 dated November 1, 1982.
(Exhibit C-101, 1982 Form 10-K, File No. 1-8222)
10.37.1 Amendment No. 3 dated January 1, 1986. (Exhibit 10-149,
1986 Form 10-K, File No. 1-8222)
10.38 Phase 1 Terminal Facility Support Agreement between New England
Electric Transmission Corporation and twenty New England
Utilities dated December 1, 1981, as amended by Amendment No. 1
dated as of June 1, 1982 and by Amendment No. 2 dated as of
November 1, 1982. (Exhibit C-102, 1982 Form 10-K, File No.
1-8222)
10.39 Power Purchase Agreement between Velco and CVPS dated June 1,
1981. (Exhibit C-103, 1982 Form 10-K, File No. 1-8222)
10.40 Agreement for Joint Ownership, Construction and Operation of
the Joseph C. McNeil Generating Station by and between City of
Burlington Electric Department, Central Vermont Realty, Inc.
and Vermont Public Power Supply Authority dated May 14, 1982.
(Exhibit C-107, 1983 Form 10-K, File No. 1-8222)
10.40.1 Amendment No. 1 dated October 5, 1982. (Exhibit C-108,
1983 Form 10-K, File No. 1-8222)
10.40.2 Amendment No. 2 dated December 30, 1983. (Exhibit C-109,
1983 Form 10-K, File No. 1-8222)
10.40.3 Amendment No. 3 dated January 10, 1984. (Exhibit 10-143,
1986 Form 10-K, File No. 1-8222)
10.41 Transmission Service Contract between Central Vermont Public
Service Corporation and The Vermont Electric Generation &
Transmission Cooperative, Inc. dated May 14, 1984. (Exhibit
C-111, 1984 Form 10-K, File No. 1-8222)
10.42 Copy of Highgate Transmission Interconnection Preliminary
Support Agreement dated April 9, 1984. (Exhibit C-117, 1984
Form 10-K, File No. 1-8222)
10.43 Copy of Allocation Contract for Hydro-Quebec Firm Power dated
July 25, 1984. (Exhibit C-118, 1984 Form 10-K, File No.
1-8222)
10.43.1 Tertiary Energy for Testing of the Highgate HVDC
Station Agreement, dated September 20, 1985. (Exhibit
C-129, 1985 Form 10-K, File No. 1-8222)
10.44 Copy of Highgate Operating and Management Agreement dated
August 1, 1984. (Exhibit C-119, 1986 Form 10-K, File No. 1-8222)
10.44.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-152,
1986 Form 10-K, File No. 1-8222)
10.44.2 Amendment No. 2 dated November 13, 1986. (Exhibit
10-167, 1987 Form 10-K, File No. 1-8222)
10.44.3 Amendment No. 3 dated January 1, 1987. (Exhibit
10-168, 1987 Form 10-K, File No. 1-8222)
10.45 Copy of Highgate Construction Agreement dated August 1, 1984.
(Exhibit C-120, 1984 Form 10-K, File No. 1-8222)
10.45.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-151,
1986 Form 10-K, File No. 1-8222)
10.46 Copy of Agreement for Joint Ownership, Construction and
Operation of the Highgate Transmission Interconnection.
(Exhibit C-121, 1984 Form 10-K, File No. 1-8222)
10.46.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-153,
1986 Form 10-K, File No. 1-8222)
10.46.2 Amendment No. 2 dated April 18, 1985. (Exhibit 10-154,
1986 Form 10-K, File No. 1-8222)
10.46.3 Amendment No. 3 dated February 12, 1986. (Exhibit
10-155, 1986 Form 10-K, File No. 1-8222)
10.46.4 Amendment No. 4 dated November 13, 1986.
(Exhibit 10-169, 1987 Form 10-K, File No. 1-8222)
10.46.5 Amendment No. 5 and Restatement of Agreement dated
January 1, 1987. (Exhibit 10-170, 1987 Form 10-K,
File No. 1-8222)
10.47 Copy of the Highgate Transmission Agreement dated August 1,
1984. (Exhibit C-122, 1984 Form 10-K, File No. 1-8222)
10.48 Copy of Preliminary Vermont Support Agreement Re: Quebec
Interconnection - Phase II dated September 1, 1984. (Exhibit
C-124, 1984 Form 10-K, File No. 1-8222)
10.48.1 First Amendment dated March 1, 1985. (Exhibit C-127,
1985 Form 10-K, File No. 1-8222)
10.49 Vermont Transmission and Interconnection Agreement between New
England Power Company and Central Vermont Public Service
Corporation and Green Mountain Power Corporation with the consent
of Vermont Electric Power Company, Inc., dated May 1, 1985.
(Exhibit C-128, 1985 Form 10-K, File No. 1-8222)
10.50 Service Contract Agreement between the Company and the State of
Vermont for distribution and sale of energy from St. Lawrence
power projects (NYPA Power) dated as of June 25, 1985.
(Exhibit C-130, 1985 Form 10-K, File No. 1-8222)
10.50.1 Lease and Operating Agreement between the Company and
the State of Vermont dated as of June 25, 1985.
(Exhibit C-131, 1985 Form 10-K, File No. 1-8222)
10.51 System Sales & Exchange Agreement Between Niagara Mohawk Power
Corporation and Central Vermont Public Service Corporation
dated October 1, 1986. (Exhibit C-133, 1986 Form 10-K, File
No. 1-8222)
10.54 Transmission Agreement between Vermont Electric Power Company,
Inc. and Central Vermont Public Service Corporation dated
January 1, 1986. (Exhibit 10-146, 1986 Form 10-K, File No.
1-8222)
10.55 1985 Four-Party Agreement between Vermont Electric Power
Company, Central Vermont Public Service Corporation, Green
Mountain Power Corporation and Citizens Utilities dated July 1,
1985. (Exhibit 10-147, 1986 Form 10-K, File No. 1-8222)
10.55.1 Amendment dated February 1, 1987. (Exhibit 10-171,
1987 Form 10-K, File No. 1-8222)
10.56 1985 Option Agreement between Vermont Electric Power Company,
Central Vermont Public Service Corporation, Green Mountain
Power Corporation and Citizens Utilities dated December 27,
1985. (Exhibit 10-148, 1986 Form 10-K, File No. 1-8222)
10.56.1 Amendment No. 1 dated September 28, 1988.
(Exhibit 10-182, 1988 Form 10-K, File No. 1-8222)
10.56.2 Amendment No. 2 dated October 1, 1991. (Exhibit
10.56.2, 1991 Form 10-K, File No. 1-8222)
10.56.3 Amendment No. 3 dated December 31, 1994.
(Exhibit 10.56.3, 1994 Form 10-K, File No. 1-8222)
10.57 Highgate Transmission Agreement dated August 1, 1984 by and
between the owners of the project and the Vermont electric
distribution companies. (Exhibit 10-156, 1986 Form 10-K, File
No. 1-8222)
10.57.1 Amendment No. 1 dated September 22, 1985. (Exhibit
10-157, 1986 Form 10-K, File No. 1-8222)
10.58 Vermont Support Agency Agreement re: Quebec Interconnection -
Phase II between Vermont Electric Power Company, Inc. and
participating Vermont electric utilities dated June 1, 1985.
(Exhibit 10-158, 1986 Form 10K, File No. 1-8222)
10.58.1 Amendment No. 1 dated June 20, 1986. (Exhibit 10-159,
1986 Form 10-K, File No. 1-8222)
10.59 Indemnity Agreement B-39 dated May 9, 1969 with amendments 1-16
dated April 17, 1970 thru April 16, 1985 between licensees of
Millstone Unit No. 3 and the Nuclear Regulatory Commission.
(Exhibit 10-161, 1986 Form 10-K, File No. 1-8222)
10.59.1 Amendment No. 17 dated November 25, 1985. (Exhibit
10-162, 1986 Form 10-K, File No. 1-8222)
10.62 Contract for the Sale of 50MW of firm power between Hydro-Quebec
and Vermont Joint Owners of Highgate Facilities dated
February 23, 1987. (Exhibit 10-173, 1987 Form 10-K, File
No. 1-8222)
10.63 Interconnection Agreement between Hydro-Quebec and Vermont
Joint Owners of Highgate facilities dated February 23, 1987.
(Exhibit 10-174, 1987 Form 10-K, File No. 1-8222)
10.63.1 Amendment dated September 1, 1993 (Exhibit 10.63.1,
1993 Form 10-K, File No. 1-8222)
10.64 Firm Power and Energy Contract by and between Hydro-Quebec and
Vermont Joint Owners of Highgate for 500MW dated December 4,
1987. (Exhibit 10-175, 1987 Form 10-K, File No. 1-8222)
10.64.1 Amendment No. 1 dated August 31, 1988. (Exhibit 10-191,
1988 Form 10-K, File No. 1-8222)
10.64.2 Amendment No. 2 dated September 19, 1990.
(Exhibit 10-202, 1990 Form 10-K, File No. 1-8222)
10.64.3 Firm Power & Energy Contract dated January 21, 1993
by and between Hydro-Quebec and Central Vermont
Public Service Corporation for the sale back of 25 MW
of power. (Exhibit 10.64.3, 1992 Form 10-K, File No.
1-8222)
10.64.4 Firm Power & Energy Contract dated January 21, 1993
by and between Hydro-Quebec and Central Vermont Public
Service Corporation for the sale back of 50 MW of
power. (Exhibit 10.64.4, 1992 Form 10-K, File No.
1-8222)
10.66 Hydro-Quebec Participation Agreement dated April 1, 1988 for
600 MW between Hydro-Quebec and Vermont Joint Owners of
Highgate. (Exhibit 10-177, 1988 Form 10-K, File No. 1-8222)
10.67 Sale of firm power and energy (54MW) between Hydro-Quebec and
Vermont Utilities dated December 29, 1988. (Exhibit 10-183,
1988 Form 10-K, File No. 1-8222)
10.75 Receivables Purchase Agreement between Central Vermont Public
Service Corporation, Central Vermont Public Service Corporation
as Service Agent and The First National Bank of Boston dated
November 29, 1988. (Exhibit 10-192, 1988 Form 10-K)
10.75.1 Agreement Amendment No. 1 dated December 21, 1988
(Exhibit 10.75.1, 1993 Form 10-K, File No. 1-8222)
10.75.2 Letter Agreement dated December 4, 1989 (Exhibit 10.75.2,
1993 Form 10-K, File No. 1-8222)
10.75.3 Agreement Amendment No. 2 dated November 29, 1990
(Exhibit 10.75.3, 1993 Form 10-K, File No. 1-8222)
10.75.4 Agreement Amendment No. 3 dated November 29, 1991
(Exhibit 10.75.4, 1993 Form 10-K, File No. 1-8222)
10.75.5 Agreement Amendment No. 4 dated November 29, 1992
(Exhibit 10.75.5, 1993 Form 10-K, File No. 1-8222)
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
A 10.68 Stock Option Plan for Non-Employee Directors dated July 18,
1988. (Exhibit 10-184, 1988 Form 10-K, File No. 1-8222)
A 10.69 Stock Option Plan for Key Employees dated July 18, 1988.
(Exhibit 10-185, 1988 Form 10-K, File No. 1-8222)
A 10.70 Officers Supplemental Insurance Plan authorized July 9, 1984.
(Exhibit 10-186, 1988 Form 10-K, File No. 1-8222)
A 10.71 Officers Supplemental Deferred Compensation Plan dated
November 4, 1985. (Exhibit 10-187, 1988 Form 10-K, File
No. 1-8222)
* A 10.71.1 Amendment dated October 2, 1995.
A 10.72 Directors' Supplemental Deferred Compensation Plan dated
November 4, 1985. (Exhibit 10-188, 1988 Form 10-K, File No.
1-8222)
* A 10.72.1 Amendment dated October 2, 1995.
A 10.73 Management Incentive Compensation Plan as adopted September 9,
1985. (Exhibit 10-189, 1988 Form 10-K, File No. 1-8222)
A 10.73.1 Revised Management Incentive Plan as adopted
February 5, 1990. (Exhibit 10-200, 1989 Form 10-K,
File No. 1-8222)
* A 10.73.2 Revised Management Incentive Plan dated May 2, 1995.
A 10.74 Officers' Change of Control Agreements as approved October 3,
1988. (Exhibit 10-190, 1988 Form 10-K, File No. 1-8222)
A 10.78 Stock Option Plan for Non-Employee Directors dated April 30,
1993. (Exhibit 10.78, 1993 Form 10-K, File No. 1-8222)
A 10.79 Officers Insurance Plan dated November 15, 1993.
(Exhibit 10.79, 1993 Form 10-K, File No. 1-8222)
* A 10.79.1 Amendment dated October 2, 1995.
A 10.80 Directors' Supplemental Deferred Compensation Plan dated
January 1, 1990. (Exhibit 10.80, 1993 Form 10-K, File No. 1-8222)
* A 10.80.1 Amendment dated October 2, 1995.
A 10.81 Officers' Supplemental Deferred Compensation Plan dated
January 1, 1990. (Exhibit 10.81, 1993 Form 10-K, File No. 1-8222)
A - Compensation related plan, contract, or arrangement.
21. Subsidiaries of the Registrant
* 21.1 List of Subsidiaries of Registrant
23. Consents of Experts and Counsel
* 23.1 Consent of Independent Public Accountants
27. Financial Data Schedule
(b) Reports on Form 8-K:
The Company filed the following reports on Form 8-K during
the quarter ended December 31, 1995:
1. Item 5. Other Events, dated October 2, 1995 re: CVPS
President Thomas C. Webb to retire at year's end.
Report of Independent Public Accountants
To the Board of Directors of
Central Vermont Public Service Corporation:
We have audited, in accordance with generally accepted auditing
standards, the consolidated financial statements included in Central Vermont
Public Service Corporation's annual report to shareholders, included in this
Form 10-K, and have issued our report thereon dated February 5, 1996. Our
audit was made for the purpose of forming an opinion on those statements
taken as a whole. The schedule listed in the index above is the
responsibility of the Company's management and is presented for purposes of
complying with the Securities and Exchange Commission's rules and is not part
of the basic financial statements. This schedule has been subjected to the
auditing procedures applied in the audit of the basic consolidated financial
statements and, in our opinion, fairly state, in all material respects, the
consolidated financial data required to be set forth therein in relation to
the basic consolidated financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Boston, Massachusetts
February 5, 1996
Schedule II
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 1995
Additions
Balance at Charged to Charged Balance at
beginning costs and to other end of
of year expenses accounts Deductions year
Reserves deducted from assets
to which they apply:
$ 80,978(1)
644,277(2)
Reserve for uncollectible 200,000(3)
accounts receivable --------
$ 967,732 $1,074,327 $925,255 $1,415,708(4) $1,551,606
========== ========== ======== ========== ==========
Accumulated depreciation of
miscellaneous properties:
Rental water heater program $3,450,284 $ 350,522 - $ 292,313(5) $3,508,493
Other 213,287 82,478 - - 295,765
---------- ---------- --------- ----------
$3,663,571 $ 433,000 $ 292,313 $3,804,258
========== ========== ======== ========== ==========
Reserve shown separately:
Injuries and damages reserve $ 225,580 - - - $ 225,580
========== ==========
(1) Amount due from collection agency.
(2) Collections of accounts previously written off.
(3) Transferred from miscellaneous receivables.
(4) Uncollectible accounts written off.
(5) Retirements of rental water heaters.
Schedule II
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 1994
Additions
Balance at Charged to Charged Balance at
beginning costs and to other end of
of year expenses accounts Deductions year
Reserves deducted from assets
to which they apply:
$ 71,210(1)
Reserve for uncollectible 335,718(2)
accounts receivable --------
$ 936,080 $547,490 $406,928 $ 922,766(3) $ 967,732
========== ========== ======== ========== ==========
Accumulated depreciation of
miscellaneous properties:
Rental water heater program $3,428,944 $265,309 - $ 243,969(4) $3,450,284
Other 68,153 145,134(5) - - 213,287
---------- -------- ---------- ----------
$3,497,097 $410,443 $ 243,969 $3,663,571
========== ========== ========== ==========
Reserve shown separately:
Injuries and damages reserve $ 225,580 - - - $ 225,580
========== ==========
(1) Amount due from collection agency.
(2) Collections of accounts previously written off.
(3) Uncollectible accounts written off.
(4) Retirements of rental water heaters.
(5) Includes reclassification of $67,201 of the Company's wholly owned subsidiary, SmartEnergy
Services, Inc.'s depreciation expense from its water heater program to other non-utility
property.
Schedule II
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 1993
Additions
Balance at Charged to Charged Balance at
beginning costs and to other end of
of year expenses accounts Deductions year
Reserves deducted from assets
to which they apply:
$ 64,809(1)
Reserve for uncollectible 324,081(2)
accounts receivable --------
$1,079,806 $960,000 $388,890 $1,492,616(3) $ 936,080
========== ======== ======== ========== ==========
Accumulated depreciation of
miscellaneous properties:
Rental water heater program $3,334,201 $352,547 - $ 257,804(4) $3,428,944
Other 41,052 27,101 - - 68,153
---------- -------- ---------- ----------
$3,375,253 $379,648 $ 257,804 $3,497,097
========== ========== ========== ==========
Reserve shown separately:
Injuries and damages reserve $ 242,901 - - $ 17,321(5) $ 225,580
========== ========== ==========
(1) Amount due from collection agency.
(2) Collections of accounts previously written off.
(3) Uncollectible accounts written off.
(4) Retirements of rental water heaters.
(5) Payments for construction accidents.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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
By /s/ Robert H. Young
------------------------------
Robert H. Young, President and
Chief Executive Officer
March 27, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
DATE NAME AND TITLE
- ----------------- -----------------------------------------
March 27, 1996 /s/ Robert H. Young
---------------------------------------
Robert H. Young
President and Chief Executive Officer
and Director
March 27, 1996 /s/ Francis J. Boyle
---------------------------------------
Francis J. Boyle, Vice President -
Finance and Administration and
Chief Financial Officer
(Principal Financial Officer)
March 27, 1996 /s/ James M. Pennington
---------------------------------------
James M. Pennington, Controller
(Principal Accounting Officer)
March 27, 1996 /s/ F. Ray Keyser, Jr.
---------------------------------------
F. Ray Keyser, Jr.
Chairman of the Board and Director
March 27, 1996 /s/ Frederic H. Bertrand
---------------------------------------
Frederic H. Bertrand
Director
March 27, 1996 /s/ Robert P. Bliss, Jr.
---------------------------------------
Robert P. Bliss, Jr.
Director
March 27, 1996 /s/ Elizabeth Coleman
---------------------------------------
Elizabeth Coleman
Director
March 27, 1996 /s/ Luther F. Hackett
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Luther F. Hackett
Director
March 27, 1996 /s/
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Mary Alice McKenzie
Director
March 27, 1996 /s/ Gordon P. Mills
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Gordon P. Mills
Director
March 27, 1996 /s/ Preston Leete Smith
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Preston Leete Smith
Director
March 27, 1996 /s/ Robert D. Stout
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Robert D. Stout
Director