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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, 1993
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: $225,818,327 based upon the closing price
as of January 31, 1994 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, 1994, there
were outstanding 11,580,427 shares of Common Stock, $6 Par Value.
DOCUMENTS INCORPORATED BY REFERENCE
The following documents, or indicated portions thereof, have been
incorporated herein by reference:
(1) Portions of the registrant's Annual Report to Stockholders for
the fiscal year ended December 31, 1993 are incorporated by
reference as Exhibit EX-13.
Cover page continued
Form 10-K - 1993
TABLE OF CONTENTS
Part I
Item 1. Business................................................
Item 2. Properties..............................................
Item 3. Legal Proceedings.......................................
Item 4. Submission of Matters to a Vote of Security Holders.....
Part II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters....................................
Item 6. Selected Financial Data.................................
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations....................
Item 8. Financial Statements and Supplementary Data.............
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure....................
Part III
Item 10. Directors and Executive Officers of the Registrant......
Item 11. Executive Compensation..................................
Item 12. Security Ownership of Certain Beneficial Owners and
Management.............................................
Item 13. Certain Relationships and Related Transactions..........
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K............................................
Signatures........................................................
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
133,658 customers in 175 of the 245 towns in Vermont. This represents
about 50% of the Vermont population. In addition, the Company supplies
electricity at wholesale to 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 59% of total MWH sales for the year 1993. Sales to the five
largest retail customers receiving electric service from the Company
during the same period constituted about 4.5% of the Company's total
electric revenues for the year. The Company's requirements resale sales
accounted for approximately 6%, entitlement sales accounted for 27% and
other resale sales which include contract sales, opportunity sales and
sales to NEPOOL accounted for approximately 8% of total MWH sales for the
year 1993.
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 10,202
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 1993. Sales to its
five largest retail customers during the same period equaled about 17% 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. The Company also has
the following wholly owned non-utility subsidiaries: C.V. Realty Inc., a
real estate company, Catamount Energy Corporation whose purpose is to
invest in energy-related projects, CV Energy Services, Inc. (a), whose
purpose was to provide energy-related services and SmartEnergy Services,
Inc., whose purpose is to cost effectively provide reliable energy
efficient products and services, including the rental of electric water
heaters.
Catamount Energy Corporation has established four wholly owned
subsidiaries: (See "DIVERSIFICATION"); Catamount Rumford Corp., Equinox
Vermont Corporation, Appomattox Vermont Corp. and Catamount Williams Lake
L.P. See Exhibit EX-13 for additional information of the Company's
diversification activities.
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 ownership as a tenant-in-common of Wyman #4 and
Millstone #3, 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"): 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.
(a) CV Energy Services, Inc. was dissolved effective March 16, 1993.
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 operations 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, because the extent of the
applicability is not known at this time. The Company believes that any
such costs related to its utility operations would be recoverable through
the rate-making process.
Refer to Exhibit EX-13 incorporated herein by reference 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 Exhibit EX-13 incorporated herein by reference for disclosures relating
to the shut down of the Yankee Atomic Nuclear Power plant.
Competition.
The Company's retail electric businesses in both Vermont and New
Hampshire are generally free from competition by other electric utilities,
municipalities or other public agencies. Pursuant to Vermont statutes (30
V.S.A. Section 249), the PSB has established as the service area for
Central Vermont 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.
However, 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. 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.
No other municipality served by the Company, so far as is known to
the Company, is taking steps in an attempt to establish a municipal
electric distribution system.
For a discussion relating to the Company's wholesale electric
business see "Wholesale Rates" below.
RATE DEVELOPMENTS
Vermont Retail Rates.
From July 1, 1985 through July 31, 1993, a block of energy obtained
by the Department of Public Service (DPS) from the New York Power
Authority (NYPA) and from Ontario Hydro was sold by the DPS directly to
the Company's retail customers. When the DPS's sources were not
sufficient, on a short-term basis, the Company provided back-up energy and
capacity to meet the DPS's block requirements. Under this arrangement,
which became effective July 1, 1989, the Company was reimbursed for all
back-up energy and capacity.
During most of 1989 the DPS's block equaled the first 200 KWH sold to
certain retail customers, but the block was reduced to 120 KWH beginning
with bills rendered on December 1, 1989, to 85 KWH beginning with bills
rendered on January 1, 1990, and to 75 KWH beginning with bills rendered
on February 3, 1992. Effective February 1, 1993, the DPS block was
reduced to a maximum of 25 KWH from 75 KWH due to the termination of the
Ontario Hydro power contract with the DPS on October 31, 1992. Since the
Company sells to customers all KWH over the DPS's block, the Company's
rates were reduced to provide the same net revenues under the 120, 85, 75,
and 25 KWH blocks as they would have under the 200 KWH block. Effective
February 1, 1992, the PSB allowed the Company to increase its billing and
service fees charged to the DPS from 2.3 cents per KWH to 3.6 cents per
KWH. The PSB subsequently delayed the effective date to December 1, 1992
but allowed the Company to collect the lost revenues plus interest after
November 1, 1992 through a 3.0% surcharge on April and May 1993 bills.
On November 18, 1992, the Company filed with the PSB a tariff in
response to expected and proposed changes to the provision of power by the
DPS. The Company proposed to supply an initial non-seasonally
differentiated block of 150 KWH/month to residential customers in the
Company's service territory. On December 22, 1992, the DPS filed with the
PSB to supply an initial block of 25 KWH/month to the Company's
residential customers, reflecting the expiration, on October 31, 1992, of
the Ontario Hydro power contract. On December 29, 1992, the PSB approved,
on an interim basis pending investigation, a joint DPS-Company block of
150 KWH/month at a non-seasonal uniform rate of 8.4 cents per KWH.
Initially, the DPS would sell the first 25 KWH and the Company would sell
the remaining 125 KWH. The PSB's interim order resulted in a non-seasonal
25 KWH block at 5.2 cents per KWH for the DPS and a non-seasonal 125 KWH
block at 9.0 cents per KWH for the Company. Accordingly, effective
February 1, 1993, the DPS block was reduced to a maximum of 25 KWH from 75
KWH.
The remaining NYPA power allotment, which was the sole remaining
power source of the DPS other than the Company, was reduced substantially
effective July 1, 1993. Effective August 1, 1993, the DPS ceased
altogether selling to the Company's retail customers. That NYPA power
allotment is now sold directly to the Company and the retail sales
formerly made by the DPS are now made by the Company. In addition, the
Company's rates now provide for an initial non-seasonal 250 KWH block of
sales to certain retail customers.
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 to a decrease in
its allowed rate of return on common equity from 12.5% to 12.0% for 1993,
to accelerate the recovery of $1.5 million of Conservation and Load
Management ("C&LM") costs deferred in 1993, 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 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 want 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.
Thus on February 15, 1994, the Company filed for a rate increase of
$17.9 million or 8.9% to become effective November 1, 1994.
The Company anticipates filing for rate increases periodically,
primarily to recover increasing purchased power and other operating costs.
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,
respectively, which are reconciled when actual data is available.
Although the tariffs provide for annual changes of the FAC and PPCA
effective January 1, the Company requested and the NHPUC approved a delay
of the effective date to March 1, 1994. The NHPUC also ordered an interim
increase in the PPCA effective December 1, 1993. On the basis of
estimates of costs for 1994 and reconciliations from 1993, the combined
PPCA and FAC will result in a decrease in revenues of approximately
$16,000 or 0.1% for 1994.
Connecticut Valley filed in 1991 to redesign the revenue recovery
from each rate component within each rate class, as well as from each rate
class, to more accurately reflect the cost of service for each rate
component and rate class. Negotiations with the NHPUC Staff resulted in a
settlement rate design which was approved by the NHPUC effective in two
steps: January 1, 1992 and March 1, 1992. The redesigned rates feature
higher rates during the winter when Connecticut Valley is likely to
experience a peak use of electricity. The settlement also provided for
subsequent phases of rate redesign. Phase 2 resulted in an increase of
the peak to off-peak season price ratio from 1.45 to 1.0 to a ratio of 1.6
to 1.0. This phase of rate redesign caused no change in the overall
revenue requirement or the allocation of the revenue requirement among
rate classes. The NHPUC approved this phase of rate redesign effective
January 1, 1993. The NHPUC approved a delay of the effectiveness of Phase
3 to 1995.
Connecticut Valley's retail rate tariffs, approved by the NHPUC, also
provide for Conservation and Load Management Percentage Adjustments
(C&LMPA) for residential and commercial/industrial customers in order to
collect deferred and 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 are made whole
through recovery of lost revenues related to fixed costs which Connecticut
Valley loses as a result of C&LM activities. However, the Company is not
made whole because the fixed costs of the wholesale transaction between
the Company and Connecticut Valley are 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.
The filing in September 1993 of the annual update of the 1994 C&LMPA
rates resulted in a delay of the effective date to March 1, 1994 and a
settlement on all issues except for one relating to the basis for
determination of lost revenues. The NHPUC approved 1994 C&LMPA rates
which result in a revenue decrease of $26,000 or 0.2%.
Effective July 1, 1993, the NHPUC allowed a revenue increase of
$127,000 or 0.8% related to Connecticut Valley's adoption of the Statement
of Financial Accounting Standards No. 106 for Postretirement Benefits
Other Than Pensions and the re-enactment of the New Hampshire Franchise
Tax.
Connecticut Valley also purchases power from several independent
power producers who own qualifying facilities under the Public Utility
Regulatory Practices Act of 1978. Connecticut Valley filed a complaint
with the Federal Energy Regulatory Commission (FERC) informing them of its
concern that a solid waste facility owned and operated by Wheelabrator
Claremont Company, L.P. has not been such a qualifying facility since the
plant began operation. The outcome of this filing is unknown at this
time. Potential outcomes of this filing could result in a refund, with
interest, of past purchased power costs as well as lower future costs.
Any refunds and future lower costs are likely to be reflected in the FAC
when known. Connecticut Valley has petitioned the NHPUC for current
recovery of costs related to pursuing this filing. Connecticut Valley has
also petitioned for a deferral of such costs if a current recovery of
these costs is not allowed by the NHPUC.
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 Company filed with the FERC for a
revenue increase of $294,300 or 3.2% for 1994 power costs. The rate
schedule provides for an automatic update of annual rates, as well as the
subsequent reconciliation to actual data.
The Company sold firm system capacity to four Vermont village
municipal electric departments ("Municipal Departments") under a wholesale
tariff based on forecast data for each calendar year which is reconciled
to actual data annually. As allowed in the tariff, the Company gave the
Municipal Departments notice of extension of termination date of the
tariff to October 21, 2008 from October 31, 1993. FERC approved the
extension of the termination date. Due to current market conditions, the
Municipal Departments did not opt to purchase power under this tariff
during the period of the extension. Sales under the tariffs terminated
October 31, 1993.
One of the Company's requirements wholesale customers, Woodsville
Fire District Water and Light Department, with a peak of 3.6 MW began
receiving power from the Company under a 15-year contract. The effective
date was May 1, 1993 and the effect was to increase revenues from the
customer.
Another of the Company's requirements wholesale customers, New
Hampshire Electric Cooperative, Inc., with an average monthly peak of 2.8
MW has given the Company notice of termination of service under FERC
Electric Tariff, First Revised Volume No. 1, effective in March 1995. The
Company will continue to provide the transmission service and will enter
into negotiations to supply power under another contract.
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 2,414,970 MWH for the year ended December 31,
1993. The maximum one-hour integrated demand during that period was 418.2
MW, which occurred on December 27, 1993. The Company's and Connecticut
Valley's total production in 1993, including production related to all
resale customers, was 3,651,319 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, 1993 and at the time of the Company's own peak. In
1993, the DPS sold 25,714 MWH of NYPA energy to residential customers in
the Company's service territory.
Year Ended December 31, 1993
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....................... 42.2 176,154 4.8 24.2 5.8
Diesel and Gas Turbine..... 28.4 228 - - -
JOINTLY OWNED PLANTS:
Millstone #3................ 19.9 112,823 3.1 19.4 4.6
Wyman #4.................... 11.0 6,736 0.2 5.0 1.2
McNeil...................... 10.5 17,079 0.5 10.3 2.5
EQUITY OWNERSHIP IN PLANTS:
(Purchased)
Vermont Yankee.............. 156.0 1,028,255 28.2 108.0 25.8
Maine Yankee................ 15.7 102,844 2.8 15.3 3.7
Connecticut Yankee.......... 11.6 74,961 2.0 11.4 2.7
MAJOR LONG-TERM PURCHASES:
Hydro-Quebec................ 179.2 853,499 23.4 70.8 16.9
Merrimack #2................ 47.0 300,666 8.2 24.6 5.9
OTHER PURCHASES:
Ontario Hydro............... 24.4 35,655 1.0 - -
Small Power Qualifying...... 33.1 186,900 5.1 12.3 2.9
Unit Purchases.............. 56.2 265,815 7.3 47.3 11.3
Entitlement Purchases....... 0.9 18,082 0.5 - -
System and Other Purchases.. 44.6 212,236 5.8 36.3 8.7
Pumped Storage Hydro........ 1.4 1,365 - - -
NEPEX......................... - 258,021 7.1 33.3 8.0
TOTAL.................... 682.1 3,651,319 100.0 418.2 100.0
Wholly Owned Plants.
The Company owns and operates 18 hydroelectric generating facilities
in Vermont which have an aggregate nameplate capability of 37.5 MW. It
also leases and operates hydroelectric facilities at Bradford and East
Barnet, Vermont. These two plants have a nameplate capability of 1.5 MW
and 2.2 MW, respectively. In addition, the Company owns and operates
diesel and gas turbine 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% 20 112,823 64% $61,363,376
Connecticut
Wyman #4 Yarmouth, Oil 1.78% 11 6,736 7% $ 1,833,631
Maine
Joseph C. McNeil Burlington, Various 20.00% 10 17,079 19% $10,516,552
Vermont
Highgate Trans- Highgate Springs, 46.08% N/A N/A N/A $ 9,552,092
mission Facility Vermont
The Company has a 1.73% joint-ownership interest in Millstone #3, an
1149 MW nuclear generating facility located in Waterford, Connecticut,
which commenced commercial operation in April 1986. Under the Millstone
Sharing Agreement, the Company is entitled to receive its share of the
output and capacity of the facility and is responsible for its share of
the operating expenses, including decommissioning.
The Company also has a 1.78% joint-ownership interest in Wyman #4, a
619 MW oil-fired generating facility located in Yarmouth, Maine and a 20%
joint-ownership interest in McNeil, a 53 MW wood, gas and oil-fired
generating facility located in Burlington, Vermont. The Company receives
its share of the output and capacity from these generating plants and is
responsible for its share of the operating expenses of each.
Finally the Company has a 46.08% joint-ownership interest in the
Highgate Convertor, a 200 MW facility located in Highgate Springs,
Vermont. This 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 4.7%
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 (F1) is
the Company's net entitlement. Vermont Yankee's plant performance for the
past five years is shown below:
Availability Capacity
Factor Factor
(F2) (F3)
1989......................... 84.2 80.1
1990......................... 84.4 80.3
1991......................... 93.6 91.2
1992......................... 87.5 82.7
1993......................... 78.3 74.9
As was 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(F4).............. 847 MW 2.0% - 16.9 MW
Connecticut Yankee............ 582 MW 2.0% - 11.6 MW
Yankee Atomic................. (F5) (F5)
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 ownership percentages are identical to the
entitlement percentages. For additional information regarding Equity
Ownership in Plants, refer to Exhibit EX-13 incorporated herein by
reference.
_______________
(FN)
(F1) Currently, the Company resells at cost, through VELCO, 23.2 MW
of its original entitlement to other Vermont utilities.
(F2) "Availability Factor" means the hours that the plant is capable
of producing electricity divided by the total hours in the period.
(F3) "Capacity Factor" means the total net electrical generation
divided by the product of the maximum dependable electrical
capacity multiplied by the total hours in the period.
(F4) Currently, the Company resells at cost 1.8 MW of its entitlement
to certain municipal utilities in Massachusetts.
(F5) Yankee Atomic permanently ceased power operations of the Yankee
Nuclear Power Station. See Decommissioning Expense discussion below.
Decommissioning Expense.
Each of the Yankee Companies 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.
The Company's entitlement percentage of decommissioning costs for
Vermont Yankee, Connecticut Yankee, Maine Yankee and Yankee Atomic 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 1988 $190 $66.5 $34.6
Maine Yankee 1987 $167 $3.3 $1.9
Connecticut Yankee 1992 $294.2 $5.9 $2.5
Yankee Atomic 1992 $200 $7.0 $3.1
On February 26, 1992, the Board of Directors of Yankee Atomic decided
to permanently discontinue operation of their plant, and, in time,
decommission the facility. The decision to prematurely retire the plant
was based on continuing regulatory uncertainty and economics.
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 and wholesale rate tariffs.
On March 18, 1993, the FERC approved the settlement agreement
regarding the decommissioning plan, recovery of plant investment and all
issues with respect to prudency of the decision to discontinue operation.
Yankee Atomic has estimated that as of December 31, 1993, its costs of
discontinuing operations are approximately $345 million, which includes
$200 million of decommissioning costs in 1992 dollars.
The Company's total current share of its cost with respect to Yankee
Atomic's decision to discontinue operation is approximately $12 million.
This amount is subject to ongoing review and revision and 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 plant will not have
a material adverse effect on the Company's earnings or financial
condition.
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 lives.
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 $165 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 contracted for uranium enrichment services through
2002. Vermont Yankee also has an enrichment contract with the DOE which
expires in 2001. However, Vermont Yankee has exercised its right to
partially terminate the DOE contract for the period 1990 to 1996.
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 current statute 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 1993 Vermont Yankee deposited approximately $37.5 million,
including $8.2 million in 1993, in an irrevocable trust to be used
exclusively for defeasing this obligation at some future date provided the
DOE complies with the terms of the aforementioned contract. In 1991 and
1992, Vermont Yankee deposited an additional amount of approximately $8.2
and $5.2 million, respectively, into this trust.
On December 31, 1991 the DOE issued a final rule amending the
Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level
Radioactive Waste. The amended final rule conforms with a March 17, 1989
ruling of the U.S. Court of Appeals for the District of Columbia that the
$.001 per KWH fee in the Standard Contract should be based on net
electricity generated and sold. The impact of the amendment on Vermont
Yankee was to reduce the basis for the fee by 6% on an ongoing basis and
to establish a receivable from the DOE at December 31, 1991 of $2.2
million for previous overbillings and accrued interest. Vermont Yankee
has recognized in its rates the full impact of the amended final rule to
the Standard Contract. The DOE is refunding the overpayments (including
interest) to utilities over the next four year period ending in 1995 via
credits against quarterly payments. Interest is based on the 90-day
Treasury Bill Auction Bond Equivalent and will continue to accrue on
amounts remaining to be credited. At December 31, 1993 and 1992
approximately $.9 and $1.6 million in principal and interest is reflected
in other accounts receivable in the Vermont Yankee's Balance Sheet.
The average cost to the Company of energy generated at the Vermont
Yankee plant was 4.04, 4.60, 3.69, 4.71 and 5.34 mills per KWH for the
years 1989 through 1993, 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.
For a complete disclosure regarding nuclear liability and insurance
see Exhibit EX-13 incorporated herein by reference.
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 state of Vermont contract, between the Company and the Vermont
Department of Public Service, terminates on September 22, 1995. The
Company receives 69 MW of firm capacity and associated energy delivered at
the Highgate interconnection.
The Company's portion of the 1987 Hydro-Quebec contract consists of:
Schedule A, 25 MW of firm capacity and associated energy to be delivered
at the Highgate interconnection through September 22, 1995. All of this
power is being sold back to Hydro-Quebec for the duration of the contract.
This sell-back of 25 MW continues as Schedule C-1 power at the termination
of the Schedule A contract. This sell-back contract is not cancelable.
Schedule C-1, 31 MW and Schedule C-2, 21 MW of firm capacity and
associated energy are to be delivered at the NEPOOL/Hydro-Quebec (Phase I
and Phase II) interconnection through October 2012. Under a cancelable
contract, the Company is selling back to Hydro-Quebec 30 MW and 20 MW of
its C-1 and C-2 entitlements, respectively, for the period ending October
31, 1996. Under the terms of this agreement, the Company can exercise an
option, on an annual basis, to cancel all or any portion of this sell-back
and resume deliveries of this power under the appropriate C-1 and C-2
schedules. Further agreements allow for the interruption of the
sell-back, and the provision of 50 MW of capacity and delivery of
associated energy for the period March through October of a given year.
The Company must return this energy by the month of March of the following
year or pay Hydro-Quebec 150% of the Schedule C-1 and Schedule C-2 energy
price. Hydro-Quebec has the option under this sell-back agreement to buy
back 50 MW for the period November 1, 1996 through October 31, 2000. This
option must be exercised no later than October 31, 1994. These sell-back
agreements provide the Company with the necessary flexibility to minimize
near-term costs while retaining the long-term benefits of the purchase
contracts. Schedule B, 92 MW of firm capacity and associated energy is
expected to be delivered at the Highgate interconnection for 20-years
beginning September 23, 1995. The Company will sell back 25 MW of
Schedule B entitlement for the period September 23 through October 31,
1995. Schedule C-4a, 24 MW of firm capacity and associated energy is
expected to be delivered over the NEPOOL/Hydro-Quebec (Phase I and Phase
II) interconnection beginning November 1, 1996 through October 31, 2012.
Details of these purchases and sell-back contracts are described in the
table that follows (dollars in thousands):
State of VT
Contract Schedule A Schedule C-1 Schedule C-2 Schedule B Schedule C-4a
Capacity in MW 69 25 31 21 92 24
Contract period 1985-1995 1991-1995 1991-2012 1992-2012 1995-2015 1996-2012
Minimum energy capacity factor 50.0% 50.0% 75.0% 75.0% 75.0% 75.0%
Minimum annual energy in MWH 302,746 109,500 201,863 138,141 606,069 155,801
Actual 1993 energy charges $7,760 $3,040 $4,300 $3,130 N/A N/A
Est. 1st year future energy charges $7,370 $3,250 $4,880 $3,340 $15,840 $4,230
Est. avg. % change from 1st yr. future (24.5)% (19.8)% 4.0% 4.0% 4.0% 4.0%
(1994-1995) (1994-1995) (1994-2012) (1994-2012) (1995-2015) (1996-2012)
Actual 1993 annual capacity charge $4,650 $2,510 $7,170 $5,040 N/A N/A
Est. 1st year future capacity charge $4,700 $2,590 $7,270 $5,050 $23,570 $6,300
Est. avg. % change from 1st yr. future (24.5)% (24.5)% - - - -
(1994-1995) (1994-1995) (1993-2012) (1994-2012) (1994-2015) (1996-2012)
Actual 1993 avg. cost in cents/KWH 2.8 5.3 6.2 6.1 N/A N/A
Est. 1st yr. future avg. cost in cents/KWH 2.8 5.3 6.0 6.1 6.5 6.8
Est. avg. % change from 1st yr future 3.5% 7.1% 1.6% 1.6% 1.6% 1.6%
(1994-1995) (1994-1995) (1994-2012) (1994-2012) (1995-2015) (1996-2012)
1993 Sell-back in MW 25 30 20
Actual 1993 sell-back revenues $5,550 $8,790 $6,200
Expected sell-back #1 revenues 25 MW 25 MW 25 MW
100% of costs 100% of costs 100% of costs
Est. 1st year future annual $5,840 $1,650 $1,110
(1994) (1995) (1995)
Est. out-yrs. average annual $4,560 $9,890
Est. average annual % change (21.9)% 1.6%
(1995) (1996-2012)
Expected sell-back #2 revenues up to 30 MH 20 MW
Approx. 78% of costs for period
Estimated average annual $8,530 $6,530
(1994-1995) (1994-1996)
Estimated average annual $1,600
(1996)
Merrimack #2 - Merrimack #2 is a 320 MW capacity coal-fired steam unit
located in Bow, New Hampshire, and is owned and operated by Public Service
Company of New Hampshire ("PSNH"). In 1968 VELCO contracted with PSNH to
purchase a block of 100 MW of the plant's output for 30 years and to pay a
proportionate share of the plant's actual capacity and operating costs.
Under an agreement dated February 10, 1968, between the Company and VELCO,
the Company buys from VELCO at VELCO's cost 47.0 MW of that block for a
30-year period commencing May 1, 1968. Northeast Utilities (N.U.) has
acquired all of PSNH's assets including the Merrimack #2 plant, pursuant
to a merger agreement in 1991.
The Merrimack 2 unit is subject to limits on sulfur dioxide ("SO2")
and Nitrogen Oxides ("NOx") starting in 1995, mandated by the Clean Air
Act Amendments ("CAAA"). The CAAA establishes SO2 allowances to reduce
SO2 emissions. PSNH 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.
The CAAA NOx limits will be specified in Administrative Rules to be
established by the state of New Hampshire. The New Hampshire Air
Resources Division ("NHARD") has a proposed rule which includes
Merrimack 2 NOx limits, that replaces a previous proposed rule submitted
to the U.S. Environmental Protection Agency ("EPA") in 1993. The current
proposed rule must be approved by the NHARD and the EPA, and implement the
NOx reductions by May 31, 1995.
PSNH expects to comply with the current proposed Merrimack 2 NOx
limits by installing Selective Noncatalytic Reduction equipment ("SNCR")
and reducing load at Merrimack 2. Installation of the SNCR will increase
capital and operating costs. PSNH will implement load reductions based on
actual unit operating characteristics and dispatch, to comply with the NOx
rule at the lowest cost. PSNH expects that an average load reduction of
22 per cent will be required for compliance. The Company will share on a
pro-rata basis the SNCR and load reduction costs, based on its share of
the VELCO contract.
Other Purchases.
Cogeneration/Small Power Qualifying - The Company continues to work
with customers exploring the opportunities for either cogeneration by
customers or the purchase by the Company of the output of small power
qualifying. Cogeneration is the production of electricity and usable
thermal energy from the same fuel. 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, 1993, the Company received 186,899 MWH from these sources for
which it paid $18,213,351.
New York Power Authority - Prior to July 1, 1985, under agreements
between the State and NYPA, the Department purchased St. Lawrence and
Niagara Project power. The Company in turn contracted with the Department
to purchase the St. Lawrence and Niagara Project power at cost, and
credited the lower cost thereof to certain of the Company's retail
customers.
From July 1, 1985 through July 31, 1993, the St. Lawrence and/or
Niagara Project power was purchased by the DPS and sold directly to
residential customers in the Company's service territory. This power is
expected to be reduced to a minimum level in July 1994 and continue at
that level through October 2003. For additional information regarding the
DPS's sales to the Company's residential customers see "Vermont Retail
Rates".
The St. Lawrence Project power continues to be available to the
Department but will be reduced each July 1 over a ten-year period until
1994, at which time the State will receive one MW of this power through
2002.
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 1993 occurred on December 27, 1993 and equaled 418.2 MW.
At the time of this peak, the Company had a reserve margin of 21%.
NEPOOL's peak for the year occurred on July 8, 1993 and totaled 19,570 MW.
NEPOOL had a 26% reserve margin at the time of its 1993 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
1993, about 35% 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. A Corporate Review Committee provides policy
guidance and reviews resource investment recommendations from the IRP
team. 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.
The Company does not currently plan to build generation resources.
The resource plan calls for investments in energy efficiency through the
1990's with additional investments in energy-efficiency programs or power
purchases beginning in the late 1990's. The energy efficiency and power
purchase commitments made in the late 1980's served the Company and its
shareholders well during the recent recessionary downturn. The resources
from developers of cogeneration projects were deferred due to decreased
need. Power purchases from Hydro-Quebec were deferred until the
mid-1990's with the ability to recall on one-year notice. Energy
efficiency investments associated with new customers and new end-uses
naturally declined during the period of reduced load growth. Thus the
resource investment strategy with inherent flexibility and diversity
provided near-term benefits with unpredictable changing economic
conditions.
Based upon current load forecasts, the Company expects to be able to
satisfy its load requirements into the mid-1990's through its ownership in
various generating facilities and purchases from various other New
England, New York, Canadian utilities, Independent Power Qualifying, 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 into the late-1990's.
TRANSMISSION
Vermont Electric Power Company, Inc.
Since 1958 VELCO has been engaged 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 the notes to financial
statements 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. 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, 1993 and
125,000 shares of Class C preferred stock, of which 100,000 shares were
outstanding at December 31, 1993. On that date there were authorized and
outstanding three issues of First Mortgage Bonds, aggregating $41,263,000,
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 1994 to transmit power to Vermont utilities. The costs of such
facilities are presently estimated at $1,833,000 including allowance for
funds used during construction calculated at a rate of approximately 4.5%.
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.
Refer to Note 2 to Consolidated Financial Statements incorporated herein
by reference for information relating to the 1985 Four-Party Agreement.
Vermont Electric Transmission Company, Inc.
In connection with the importation of Canadian power, VELCO has
created a wholly owned subsidiary, Vermont Electric Transmission Company,
Inc. ("VETCO"), to construct, finance 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 has 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,
1993) 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, 1993 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 twenty-year
recovery period through and including 2006. Phase II transmission line
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.
Expenditures in 1992 and 1993 were $4.3 million and $9.5 million,
respectively, and are planned to be approximately $5.4 million in 1994.
The amount of expenditures will be adjusted annually, based on the
cost-effectiveness of programs compared to other options.
The PSB has approved all of the Company's C&LM programs delivered in
Vermont, which include direct utility investments in customer premises to
increase customer participation. In addition, the PSB has approved a
Monitoring and Evaluation Plan utilized to evaluate the continued
cost-effectiveness of the C&LM programs.
In late 1993, the Company filed a Petition to amend and slow the pace
of its C&LM programs in light of the excess capacity in the region which
made some of the C&LM programs less effective in the near-term. The
revised programs focus on improving efficiencies based on lessons learned
in the past several years. In addition, the programs focus on
incorporating efficiencies for new construction and remodeling programs
that have long useful lives. In the Petition, the Company stated it
planned to implement the program amendments with or without PSB approval
starting in 1994. By letter dated January 20, 1994, the PSB indicated it
would not be opening proceedings concerning the Petition at this time.
However, many of the issues raised in the Petition are before the PSB,
along with deferred C&LM expenditures and related lost revenues from 1991
to the present, in the PSB's investigation of our rates.
In addition, in Vermont, the Company is involved in several cases
related to C&LM activities including the role of fuel switching as a C&LM
measure, the level of externalities for electricity and the role of fuel
choice in new construction.
In an order dated December 29, 1992, the NHPUC approved C&LM programs
of the Company's wholly owned New Hampshire subsidiary, Connecticut Valley
Electric Company Inc. Currently, the NHPUC staff and the Company have
reached agreement on all of the issues but one concerning the 1994 C&LM
expenditures and related lost revenues. These expenditures and lost
revenues are recovered along with shareholder incentives for 1993 program
activity through a C&LM percentage adjustment clause applied March 1, 1994
through the end of 1994. The only issue awaiting clarification by the
NHPUC is the method for calculating lost revenues. The agreement reached
by the Company and the NHPUC staff includes a pilot program through which
costs of C&LM services will be billed directly to customers.
To support delivery and evaluation of the programs, a complex
infrastructure of information systems, technical audit software packages
to estimate savings for efficiency measures and a comprehensive program
tracking system to track all efficiency activity by individual customers
was also put into place in 1992. Additionally, extensive training was
conducted with employees and information programs were directed at
customers throughout 1992.
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.
Competition here is primarily for 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 issues here that favor electricity,
are the cost of back up power sources, space requirements, noise problems,
and maintenance requirements.
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
Catamount Energy Corporation (Catamount) was formed for the purpose
of investing in non-regulated energy-related projects. Currently,
Catamount has four wholly owned subsidiaries with interests in four
operating independent power projects located in Rumford, Maine;
East Ryegate, Vermont; Hopewell, Virginia; and Williams Lake,
British Columbia, Canada.
Effective January 1, 1993, the Company formed a new non-utility
subsidiary, SmartEnergy Services, Inc. The purpose of this subsidiary is
to cost effectively provide reliable, energy efficient products and
services, including the rental of electric water heaters. For additional
information regarding the Company's diversification activities, see
Exhibit EX-13 incorporated herein by reference.
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, 1993 the
Company and its wholly owned subsidiaries employed 775 persons, of which
264 are represented by the union. On December 18, 1989, the Company and
its employees represented by the union agreed to a three-year contract,
which provided for annual wage increases of 3%, 3.25% and 4.5% in 1990,
1991 and 1992, respectively. This contract expired on December 31, 1992.
The current contract, which was approved on December 31, 1992 and
effective January 1, 1993, provides for an annual wage increase of 3.95%
for a three year period ending December 31, 1995.
In the first quarter of 1994, the Company offered a Voluntary
Retirement Program (VRP) to eligible employees. Approximately 40
employees accepted the offer. The estimated benefit obligation for 1994
is about $4.4 million. This amount consists of pension benefits and
postretirement medical benefits of $2.2 million and $2.2 million,
respectively. For rate-making purposes, the Company received an
accounting order from the PSB dated March 11, 1994, requiring the Company
to defer these costs and amortize them over a five-year period beginning
June 1, 1994 and ending May 31, 1999. Additionally, the Company also
offered a Voluntary Severance Program (VSP) to certain employees. For
additional information in regard to the VRP and VSP programs, see Exhibit
EX-13 incorporated herein by reference.
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 Exhibit EX-13
incorporated herein by reference.
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.
The electric transmission and distribution systems of the Company
include about 613 miles of overhead transmission lines, about 7,136 miles
of overhead distribution lines and about 192 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 422 miles of overhead distribution lines and
about nine 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; and
on the south with the facilities of Vermont Yankee.
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 December 5, 1991, Bonneville Pacific Corporation (Bonneville)
filed for protection under Chapter 11 of the Bankruptcy Laws. On
August 30, 1993, Bonneville's trustee in bankruptcy filed suit in the
United States Bankruptcy Court in Utah, claiming damages in excess of two
million dollars in connection with two contracts between Bonneville and
the Company concerning the development of a 52 MW co-generation plant in
Vermont and the sale of power from the plant to the Company. The Company
and Bonneville have settled the case and Bonneville's claim has been
dismissed with prejudice.
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 has filed an answer denying
the allegations and does not expect the resolution of the case to have a
material affect on the business or financial condition of the Company.
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 1993.
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
1993
First quarter.............. $ 25 5/8 $ 24 1/8
Second quarter............. 25 1/8 22
Third quarter.............. 24 3/4 23 1/4
Fourth quarter............. 23 3/4 20 1/8
1992(F1)
First quarter.............. $ 22 7/8 $ 19 5/8
Second quarter............. 21 1/4 19 1/2
Third quarter.............. 22 1/2 20 7/8
Fourth quarter............. 25 21 1/8
(FN)
(F1)Retroactively adjusted to reflect the three-for-two
stock split on February 11, 1993.
(b) As of December 31, 1993, there were 16,620 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 1993 and
post-split cash dividends of $.3475 per share were paid for all quarters
of 1992.
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, 1993, the Common Stock Equity of the Company was 52.7% of
total capitalization.
For additional information regarding dividend restrictions see
Exhibit EX-13 incorporated herein by reference.
Item 6. Selected Financial Data.
Information required to be furnished in response to this Item is
submitted as Exhibit EX-13 incorporated herein by reference.
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations.
Information required to be furnished in response to this Item is
submitted as Exhibit EX-13 incorporated herein by reference.
Item 8. Financial Statements and Supplementary Data.
Information required to be furnished in response to this Item is
submitted as Exhibit EX-13 incorporated herein by reference.
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. In accordance with the Company's By-Laws, the Board of
Directors has fixed at ten (10) the number of Directors for the ensuing
year. The Directors whose terms will expire at the 1994 Annual Meeting of
Stockholders are Frederic H. Bertrand, Mary Alice McKenzie and Robert D.
Stout. Each of these Directors will stand for re-election to a three-year
term expiring in 1997. Proxies will be voted (unless otherwise
instructed) in favor of the election of the three nominees as indicated in
the table below.
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 1994 Annual Meeting. 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. 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.
Names and Principal Occupation Served as
of Nominees and Directors Age Director Since
Nominees whose terms will expire in 1997:
FREDERIC H. BERTRAND 57 1984
Chairman of the Board and
Chief Executive Officer,
National Life Insurance Co.
Montpelier, Vermont
MARY ALICE MCKENZIE 36 1992
President,
John McKenzie Packing Co., Inc.
Burlington, Vermont
(Manufacturer of Meat Products)
ROBERT D. STOUT 67 1985
Retired President and
Chief Executive Officer,
Putnam Memorial Health Corporation
Bennington, Vermont
Directors whose terms will expire in 1996:
ROBERT P. BLISS, JR. 70 1973
President,
Bob Bliss, Ltd.
St. Albans, Vermont
(Insurance Industry Consultants)
ELIZABETH COLEMAN 56 1990
President,
Bennington College
Bennington, Vermont
PRESTON LEETE SMITH 63 1977
President and Chief Executive Officer,
S-K-I Ltd.
c/o Killington Ltd.
Killington, Vermont
(Ski Business)
THOMAS C. WEBB 59 1986
President and Chief Executive Officer,
Central Vermont Public Service Corporation
Rutland, Vermont
Directors whose terms will expire in 1995:
LUTHER F. HACKETT 60 1979
President,
Hackett, Valine & MacDonald, Inc.
Burlington, Vermont
(Insurance Agents)
F. RAY KEYSER, JR. 66 1980
Chairman of the Board,
Central Vermont Public
Service Corporation,
Of Counsel, Keyser, Crowley,
Meub, Layden, Kulig &
Sullivan, P.C.
Rutland, Vermont
(Lawyers)
GORDON P. MILLS 57 1980
Chairman,
EHV-Weidmann Industries, Inc.
St. Johnsbury, Vermont
(Manufacturer of Electric
Transformer Insulation)
The following table sets forth the names and ages of all executive
officers of the Company, all positions and offices held within the Company,
as well as work experience and positions held during the past five years.
None of the executive officers of the Company has any family relationship
with any other executive officer of the Company.
Executive Officers of the Registrant:
Name and Age Office Officer Since
Thomas C. Webb, 59 President and Chief
Executive Officer 1985
Robert H. Young, 46 Executive Vice President
and Chief Operating Officer 1987
Steven J. Allenby, 39(F1) Senior Vice President-
Marketing and Customer Services 1985
Robert de R. Stein, 44 Senior Vice President-
Engineering and Energy Resources 1988
Jacquel-Anne Chouinard, 54 Vice President-Human Resources 1986
Thomas J. Hurcomb, 56 Vice President-Marketing and
Public Affairs 1975
Robert G. Kirn, 42 Vice President-Division
Operations 1991
Donald L. Rushford, 63 Vice President and General
Counsel 1972
Patricia A. Wakefield, 51(F1) Vice President-Marketing and
Customer Services 1988
William J. Deehan, 41 Assistant Vice President-Rates
and Economic Analysis 1991
Jonathan W. Booraem, 55 Treasurer 1984
James M. Pennington, 38 Controller 1993
Joseph M. Kraus, 39 Secretary and General Counsel 1987
Mr. Webb joined the Company in 1985 as Executive Vice President -
Finance and Administration and in 1986 was also designated Chief Operating
Officer. He was elected Director, President and Chief Executive Officer on
July 1, 1986. From 1977 to 1985, Mr. Webb was employed by Central Maine
Power Company as Senior Vice President - Finance and Administration and in
other executive positions.
Mr. Young joined the Company in 1987 as Vice President - Finance and
Administration. Mr. Young was named Senior Vice President - Finance and
Administration in 1988, and in 1993 was elected Executive Vice President
and Chief Operating Officer. During 1985-1986, he served as Senior
Management Consultant for A. D. Little Co.
Mr. Stein joined the Company on June 1, 1988 as Assistant Vice
President - Energy Planning. Mr. Stein was elected Vice President - Energy
Supply Planning and Engineering effective January 1, 1990, and Senior Vice
President - Engineering and Energy Resources in 1993. During the period
1984-1988, he served United Illuminating Company as Manager of Revenue
Requirements and Manager of Generation Planning and Power Contracts.
Ms. Chouinard joined the Company in 1985 as Director - Human
Resources. She was elected Assistant Vice President - Human Resources in
1986 and assumed her present position in 1988.
Mr. Hurcomb joined the Company in 1967 in the Marketing and customer
Service area. 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. From 1979 to 1991, he was employed by New York State Electric
& Gas Corporation. He served as Operations Manager of the Lancaster
Division Electric from 1988 until 1991 and as Operating Superintendent of
the Berkshire District from 1985 to 1988.
Mr. Rushford joined the Company in 1972 and has served as Vice
President and General Counsel since that time. Mr. Rushford retired
effective January 1, 1994.
Mr. Deehan joined the Company in 1985. Prior to being elected to his
present position, he served as Director of Rate Administration and
Forecasting since 1987 and as Energy Forecaster from 1985-1987.
Mr. Booraem has been with the Company since 1969. Prior to being
elected Treasurer in 1984, he was Director of Finance & Planning.
Mr. Kraus joined the Company in 1981 as Assistant Corporate Counsel.
He was named Associate Corporate Counsel in 1983 and Senior Corporate
Counsel in 1987. He was also 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 as Director of Taxes. 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. From 1984 to
1989, he served as Senior Tax Accountant for Northern Indiana Public
Service Company.
(FN)
(F1) Steven J. Allenby and Patricia A. Wakefield resigned from the
Company effective October 31, 1993.
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
Chief Executive Officer and the Company's four other most highly
compensated policy making executive officers ("officer(s)") whose direct
cash compensation for services rendered to the Company and its subsidiaries
in all capacities exceeded $100,000.
I. SUMMARY COMPENSATION TABLE
Long-Term
Compensation
Annual Compensation Awards
(a) (b) (c) (d) (g) (i)
Name and Options/ All Other
Principal Salary Bonus SARs Compensation
Position Year ($)(F1) ($)(F2) (#)(F3) ($)(F4)
A. Thomas C. Webb 1993 248,755 67,183 8,000/0 12,453
President and CEO 1992 244,694 73,000 6,000/0 17,850
1991 236,966 81,409 6,000/0 17,513
B. Robert H. Young, Jr. 1993 141,769 35,995 6,000/0 4,533
Executive Vice President 1992 130,667 34,073 4,500/0 4,363
and Chief Operating 1991 121,574 35,868 4,500/0 3,942
Officer
C. Robert de R. Stein 1993 114,677 16,804 4,500/0 3,988
Senior Vice President - 1992 105,473 18,728 3,000/0 3,472
Engineering and Energy 1991 97,881 24,126 3,000/0 3,138
Resources
D. Donald L. Rushford 1993 103,794 16,463 3,000/0 6,493
Vice President and 1992 104,001 18,700 3,000/0 4,620
General Counsel 1991 96,318 23,100 3,000/0 4,240
(Retired Effective 1/1/94)
E. Thomas J. Hurcomb 1993 98,382 15,606 3,000/0 4,996
Vice President - 1992 98,649 17,766 3,000/0 4,355
Marketing and 1991 92,863 22,894 3,000/0 3,304
Public Affairs
(FN)
(F1) - 1993 includes compensation deferred at the election of all executive
officers named and directors' retainers and fees earned from VELCO by Mr. Webb.
- 1992 calendar year includes 53 pay periods.
- Includes compensation for services performed by Mr. Webb for Vermont
Yankee and by Mr. Stein for VELCO for which the Company was reimbursed.
- 1991 includes salary increases earned in 1991 but deferred until 1992 as
follows: For A: $6,966; for B: $3,574; for C: $2,881; for D: $2,753; and for E:
$2,733.
(F2) Includes incentive bonuses awarded by Catamount Energy Corporation in 1992
and 1993 and by CV Energy Resources, Inc. in 1991, both wholly owned subsid
iaries, as follows:
For A: 1993 - $10,000, 1992 - $5,000, 1991 - $12,409; for B: 1993 -$10,000,
1992 - $5,000, 1991 - $6,368; for C: 1991 - $5,126; for D: 1991 - $4,910; and
for E: 1991 - $4,864.
(F3) In 1991, the Board of Directors rescinded provisions of the 1988 Stock
Option Plan for Key Employees permitting grants of SAR's.
(F4) The total amounts shown in this column for the last fiscal year are
comprised as follows:
(i) Company matching contributions to the Employee Savings and Investment
Plan includes for A: $8,185; for B: $4,253; for C: $3,785; for D: $2,784; and
for E: $3,250.
(ii) Premium on executive split-dollar insurance (an insurance plan that
gives both employer and employee an interest in a life insurance policy on the
employee's life) for A: $1,801; for B: $280; for C: $203; for D: $791; and for
E: $494.
(iii) Includes accrued above-market interest on deferred compensation for
A: $2,467; for D: $2,918; and for E: $1,252.
STOCK OPTIONS
The following table sets forth options granted to the Company's chief
executive officer and the Company's four other most highly compensated
executive officers during 1993 under the Company's 1988 Stock Option Plan.
Under SEC regulations, companies are required to project an estimate of
appreciation of the underlying shares of stock during the option term. The
Company has chosen the Black-Scholes model formula approved by the SEC.
However, the ultimate value will depend on the market value of the
Company's stock at a future date, which may or may not correspond to the
projections below.
II. OPTION/SAR GRANTS TABLE
Option/SAR Grants in Last Fiscal Year
Grant Date
Individual Grants Value
(a) (b) (c) (d) (e) (f)
% of
Number of Total
Securities Options/
Underlying SARs
Options/ Granted to Exercise Grant
SARs Employees or Base Expira- Date
Granted in Fiscal Price tion Present
Name (#)(F1) Year ($/Sh)(F2) Date Value($)(F3)
Thomas C. Webb 8,000/0 18.1% $24.375 5/4/03 $19,600
Robert H. Young, Jr. 6,000/0 13.5 24.375 5/4/03 14,700
Robert deR. Stein 4,500/0 10.2 24.375 5/4/03 11,025
Donald L. Rushford 3,000/0 6.8 24.375 5/4/03 7,350
Thomas J. Hurcomb 3,000/0 6.8 24.375 5/4/03 7,350
(FN)
(F1) A total of 44,300 shares were awarded to all plan participants in 1993.
Stock options are exercisable in whole or in part from the date of the grant
for a period of ten years and one day.
(F2) The exercise price reflects the post-split price and unexercised shares
have been adjusted for the 3 for 2 common stock split effective 2/11/93. The
exercise price represents the fair market value of the Company's Common Stock on
the date of the grant.
(F3) Per Black-Scholes model as certified by independent consultant. The
assumptions used for the Model are as follows: Volatility-.18 based on
quarterly prices for the period of 3/31/87 to 12/31/93; Risk free rate of
return-6%; Dividend Yield-6.5% over period of 3/31/87 to 12/31/93; and Term of
Exercise-10 years.
The following table sets forth stock options exercised by the
Company's Chief Executive Officer and the Company's four other most highly
compensated executive officers during 1993, and the number and value of all
unexercised options at year-end. The value of "in-the-money" options
refers to options having an exercise price which is less than the market
price of the Company's stock on December 31, 1993.
III. OPTION/SAR EXERCISES AND YEAR-END VALUE TABLE
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Value
(a) (b) (c) (d) (e)
Value of
Number of Unexercised
Unexercised In-the-Money
Options/SARs Options/SARs
at FY-End (#) FY-End ($)
Shares Acquired Value Exercisable/ Exercisable/
Name on Exercise (#) Realized($)(F1)Unexercisable Unexercisable(F1)
Thomas C. Webb 6,000 $41,125 14,000/0 $ 3,500/0
Robert H. Young, Jr. - - 14,625/0 14,656/0
Robert de R. Stein - - 15,000/0 28,060/0
Donald L. Rushford 5,000 31,875 3,000/0 0/0
Thomas J. Hurcomb - - 15,000/0 35,120/0
(FN)
(F1) The dollar values 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.
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 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 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. This
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 "Plan") covers employees, among others, who are officers.
The Company pays the full cost of the Plan.
The table below shows the annual amounts payable under the present
provisions of the Plan as amended through December 31, 1993, based on Final
Average Earnings for various years of service, assuming the employee would
retire at age 65 in 1994.
Assumed
5-Year Final Years of Service
Average Earnings 15 20 25 30 35
$ 80,000 $19,085 $25,447 $31,809 $ 38,171 $ 40,171
100,000 24,335 32,447 40,559 48,671 51,171
120,000 29,585 39,447 49,309 59,171 62,171
140,000 34,835 46,447 58,059 69,671 73,671
160,000 40,085 53,447 66,809 80,171 84,171
180,000 45,335 60,447 75,559 90,671 95,671
220,000 55,632 74,176 92,720 111,263 116,744
260,000 55,632 74,176 92,720 111,263 116,744
300,000 55,632 74,176 92,720 111,263 116,744
340,000 55,632 74,176 92,720 111,263 116,744
Final Average Earnings is the highest five-year average of consecutive
years' Base Salary (item (c) from the Summary Compensation Table) over an
employee's career with the Corporation.
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, 1993 under the Plan for
those individuals named in the Summary Compensation Table were as follows:
Mr. Webb, 9 years; Mr. Young, 6 years, 6 months; Mr. Stein, 5 years, 7
months; Mr. Rushford, 21 years, 6 months; and Mr. Hurcomb, 26 years.
OFFICERS' INSURANCE AND SUPPLEMENTAL RETIREMENT PLAN
The Officers' Insurance and Supplemental Retirement Plan (the "Plan")
is designed to supplement the retirement benefits available to the
Company's officers. The Plan is a part of the Company's overall strategy
for attracting and maintaining top managerial talent in the utility
industry. The Company pays the entire cost of the Plan.
Under the Plan, each officer is entitled to receive, upon his or her
retirement at age 65, fifteen annual payments in amounts equal to a
specified percentage of his or her final year's Base Salary (item (c) from
the Summary Compensation Table). A reduced benefit is available at age 60
with ten years of service.
The applicable percentages for the individuals named in Summary
Compensation Table are as follows: Mr. Webb, 44.5%; Mr. Young, 33%; Mr.
Stein, 33%; Mr. Rushford, 33%; and Mr. Hurcomb, 33%.
Shown below is the estimated Company provided benefit payable at age
65 for those individuals named in the Summary Compensation Table who
receive a benefit under the Officers' Insurance and Supplemental Retirement
Plan:
Assumed Final
Annual Base Pay
$ 33% 44.5%
80,000 26,400 35,600
100,000 33,000 44,500
120,000 39,600 53,400
140,000 46,200 62,300
160,000 52,800 71,200
180,000 59,400 80,100
220,000 72,600 97,900
260,000 85,800 115,700
300,000 99,000 133,500
340,000 112,200 151,300
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.
Shown below is the estimated Company-provided benefit, payable at age
65, for those individuals named in the Summary Compensation Table who
elected to participate. Since these benefits do not apply to all of the
named individuals, they have not been reflected in the foregoing pension
table.
Annual Company-
Provided Benefit
Name Payable at Age 65
Mr. Webb $29,800
Mr. Rushford 19,700
Mr. Hurcomb 13,900
Item 12. Security Ownership of Certain Beneficial Owners and Management.
Section 16(a) of the Securities and Exchange Act of 1934 requires the
Company's Officers and Directors to file reports of ownership and changes
in ownership of Company securities with the Securities and Exchange
Commission and to furnish the Company with copies of all such reports. In
1993, Director Mary Alice McKenzie inadvertently failed to file with the
Securities and Exchange Commission on a timely basis one required report
involving one transaction in Common Stock of the Company which she
beneficially owns. Except for the foregoing, the Company believes that
during 1993 all filing requirements applicable to its Officers and
Directors have been met. In making this statement, the Company has relied
on copies of reports that have been filed with the Commission.
Section 16(a) of the Securities Exchange Act of 1934 also requires
executive officers and directors 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.
Based solely on a review of the copies of such forms prepared and
filed during 1993 on behalf of our 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.
The following is a tabulation of equity securities of the Company
beneficially owned by all present Directors and Executive Officers of the
Company as a group (19 persons) as of January 31, 1994. No Director,
nominee for Director or Executive Officer owns any shares of the various
classes of the Company's outstanding non-voting preferred stock.
Title of Class Amount Beneficially Owned Percent of Class
Common Stock,
$6 Par Value 187,908 shares (F1) 1.6%
(FN)
(F1) Includes 124,625 shares that the directors and executive officers
have a right to acquire pursuant to options granted under Stock Option
plans.
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.
Item 13. Certain Relationships and Related Transactions.
None.
Filed
Herewith
at Page
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K.
(a) The following documents are filed as part of this
report:
1. Management's Discussion:
1.1 Central Vermont Public Service Corporation
and its wholly owned subsidiaries: (See Item 7)
Management's Discussion and Analysis of
Financial Condition and Results of Operations
2. Financial Statements:
2.1 Central Vermont Public Service Corporation and
its wholly owned subsidiaries: (See Item 8)
Consolidated Statement of Income,
years ended December 31, 1993,
1992, and 1991.
Consolidated Statement of Cash Flows,
years ended December 31, 1993, 1992
and 1991.
Consolidated Balance Sheet,
December 31, 1993 and 1992.
Consolidated Statement of Capitalization,
December 31, 1993 and 1992.
Consolidated Statement of Changes in Common
Stock Equity, years ended December 31, 1993,
1992 and 1991.
Notes to Consolidated Financial Statements.
3. Financial Statement Schedules:
3.1 Central Vermont Public Service Corporation and
its wholly owned subsidiaries:
Schedule V - Utility Plant, years ended
December 31, 1993, 1992 and 1991.
Schedule VI - Accumulated Depreciation of
Utility Plant, years ended December 31, 1993,
1992 and 1991.
Filed
Herewith
at Page
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K Continued.
Schedule VIII - Reserves, years ended
December 31, 1993, 1992 and 1991.
Schedule IX - Short-term borrowings,
years ended December 31, 1993, 1992 and 1991.
3.2 Financial Statements and Schedules for Vermont
Yankee Nuclear Power Corporation - per index
attached.
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. Other than Vermont Yankee Nuclear Power
Corporation, 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.
(b) Reports on Form 8-K:
There were no reports on Form 8-K for the quarter ended
December 31, 1993.
(c) See exhibits index.
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 incorporated by
reference in this Form 10-K, and have issued our report thereon dated
February 7, 1994. Our audit was made for the purpose of forming an
opinion on those statements taken as a whole. The schedules listed in the
index above are the responsibility of the Company's management and are
presented for purposes of complying with the Securities and Exchange
Commission's rules and are not part of the basic financial statements.
These schedules have 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 & CO.
Boston, Massachusetts,
February 7, 1994
Schedule V
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Utility Plant and Nuclear Fuel
Years ended December 31, 1993, 1992 and 1991
Description 1993 1992 1991
Electric plant:
Intangible $ 9,530,882 $ 9,530,962 $ 864,165
Production 127,113,202 127,151,910 125,136,959
Transmission 60,588,771 61,175,146 62,032,252
Distribution 162,583,392 158,350,306 153,931,597
General 33,514,895 31,974,205 30,587,869
Electric plant purchased - - 463,432
Completed construction not classified 32,905,951 19,678,446 12,867,786
Completed retirements not classified (4,308,252) (1,165,859) (790,101)
Construction work in progress 8,388,392 10,534,478 13,945,677
430,317,233 417,229,594 399,039,636
Nuclear fuel:
Fuel in refinement (921) 339,386 15,582
Fuel in stock 123,885 192,150 190,552
Fuel in reactor 2,169,513 2,581,613 2,581,613
Fuel spent 3,996,750 2,768,689 2,768,689
6,289,227 5,881,838 5,556,436
$436,606,460 $423,111,432 $404,596,072
____________ ____________ ____________
(FN)
(a)Neither total additions of $18,442,288, $19,916,850 or $18,077,565 nor
total retirements of $4,947,180, $1,401,490 or $2,671,746 for the years
ended December 31, 1993, 1992 and 1991, respectively, exceeded 10% of
the utility plant balance at the end of the year.
Schedule VI
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Accumulated Depreciation
Of Electric Plant And
Amortization Of Nuclear Fuel
Years ended December 31, 1993, 1992 and 1991
1993 1992 1991
Balance at beginning of year $102,328,927 $ 88,780,026 $79,381,919
Additions:
Charges to expense 15,246,243 14,265,003 12,264,213
Salvage value of plant retired 660,011 556,873 762,217
Other(F1) - 1,188,239 -
Total additions 15,906,254 16,010,115 13,026,430
Deductions:
Retirements, renewals and replacements 4,944,980 1,401,490 2,684,708
Removal cost of plant retired during the year 991,631 1,059,724 943,615
Total deductions 5,936,611 2,461,214 3,628,323
Total accumulated depreciation 112,298,570 102,328,927 88,780,026
Accumulated amortization of nuclear fuel 4,899,751 4,385,120 3,837,982
Balance at end of year $117,198,321 $106,714,047 $92,618,008
____________ ____________ ___________
(FN)
(F1) Prior years depreciation expense related to electric plant purchased
in 1991.
Schedule VIII
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(F1)
Reserve for uncollectible 324,081(F2)
accounts receivable $1,079,806 $960,000 $388,890 $1,492,616(F3) $ 936,080
__________ ________ ________ __________ __________
Accumulated depreciation of
miscellaneous properties:
Rental water heater program $3,334,201 $352,547 - $ 257,804(F4) $3,428,944
Non-utility property 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(F5) $ 225,580
__________ __________ __________
(FN)
(F1) Amount due from collection agency.
(F2) Collections of accounts previously written off.
(F3) Uncollectible accounts written off.
(F4) Retirements of rental water heaters.
(F5) Payments for construction accidents.
Schedule VIII
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 1992
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:
Reserve for uncollectible
accounts receivable $ 992,433 $1,018,700 $355,472(F1) $1,286,799(F2) $1,079,806
__________ __________ ________ __________ __________
Accumulated depreciation of
miscellaneous properties:
Rental water heater program $3,283,660 $ 350,642 - $ 300,101(F3) $3,334,201
Non-utility property 293,777 27,958 - 280,683(F4) 41,052
$3,577,437 $ 378,600 $ 580,784 $3,375,253
__________ __________ __________ __________
Reserve shown separately:
Injuries and damages reserve $ 268,077 - - $ 25,176(F5) $ 242,901
__________ __________ __________
(FN)
(F1) Collection of accounts previously written off.
(F2) Uncollectible accounts written off.
(F3) Retirements of rental water heaters.
(F4) Retirement of non-utility property.
(F5) Payments for construction accidents.
Schedule VIII
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 1991
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:
Reserve for uncollectible
accounts receivable $ 726,992 $1,353,084 $147,337(F1) $1,234,980(F2) $ 992,433
__________ __________ ________ __________ __________
Accumulated depreciation of
miscellaneous properties:
Rental water heater program $3,197,620 $ 327,586 $ - $ 241,546(F3) $3,283,660
Non-utility property - 51,068 242,709(F4) - 293,777
$3,197,620 $ 378,654 $242,709 $ 241,546 $3,577,437
__________ __________ ________ __________ __________
Reserve shown separately:
Injuries and damages reserve $ 262,584 $ - $ 16,289(F5) $ 10,796(F6) $ 268,077
__________ __________ ________ __________ __________
(FN)
(F1) Collections of accounts previously written off.
(F2) Uncollectible accounts written off.
(F3) Retirements of rental water heaters.
(F4) Transfer from utility property to non-utility property.
(F5) Charged to construction and retirement work in progress.
(F6) Payments for construction accidents.
Schedule IX
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Short-Term Borrowings
Years Ended December 31, 1993, 1992, 1991
Interest Rate Maximum Average Weighted Average
Category of Aggregate Balance at at End of Amount Outstanding Amount Outstanding Interest Rate
Short-Term Borrowings End of Period Period at any Month-end During the Period (F2) During the Period(
Notes Payable to Banks (F1)
Period Ending - 1993..... $ 1,356,000 5.20% $43,945,000 $ 8,488,000 3.67%
Period Ending - 1992..... $ 2,100,000 4.22% $ 2,100,000 $ 186,000 4.30%
Period Ending - 1991..... - - $18,700,000 $ 5,769,000 6.16%
(FN)
(F1) The Company had committed lines of credit amounting to $19,500,000 and
uncommitted loan facilities amounting to $25,000,000 at December 31, 1993.
The Company had fee arrangements on some of these short-term borrowing
arrangements.
(F2) Average amount outstanding computed by using daily debt balances.
(F3) The weighted average interest rate is computed by using daily
debt balances and daily interest expense.
Independent Auditor's Report
The Stockholders and Board of Directors Vermont Yankee Nuclear Power
Corporation:
We have audited the accompanying balance sheet of Vermont Yankee Nuclear
Power Corporation as of December 31, 1993, and the related statements of
income and retained earnings and cash flows for the year then ended. 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 audit. The financial statements of Vermont Yankee Nuclear
Power Corporation as of December 31, 1992 and 1991, were audited by other
auditors whose report, dated February 5, 1993, expressed an unqualified
opinion on those statements and included an additional paragraph
discussing the Company's 1992 change in accounting for postretirement
benefits other than pensions.
We conducted our audit 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 audit
provides 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 Vermont Yankee Nuclear
Power Corporation as of December 31, 1993, and the results of its
operations and cash flows for the year then ended, in conformity with
generally accepted accounting principles.
As discussed in note 10 of the accompanying financial statements,
effective January 1, 1993 the Company adopted the provisions of Statement
of Financial Accounting Standards No. 109, "Accounting for Income Taxes".
Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as whole. The supplementary schedules are
presented for purposes of additional analysis and are not a required part
of the basic financial statements. This information has been subjected to
the auditing procedures applied in our audit of the basic financial
statements and, in our opinion, is fairly stated, in all material
respects, in relation to the basic financial statements taken as a whole.
Arthur Andersen & Co.
Boston, Massachusetts January 27, 1994
VERMONT YANKEE NUCLEAR POWER CORPORATION
Index to Financial Statements and Financial Statement Schedules
Financial Statements:
Balance Sheets, December 31, 1993 and 1992
Statements of Income and Retained Earnings, years ended
December 31, 1993, 1992 and 1991
Statements of Cash Flows, years ended December 31 ,1993,
1992 and 1991
Notes to Financial Statements
Financial Statement Schedules:
Schedule I - Marketable Securities and Other Investments
at December 31, 1993
Schedule V - Property, Plant and Equipment, years ended
December 31, 1993, 1992 and 1991
Schedule VI - Accumulated Depreciation, Depletion and
Amortization of Property, Plant and Equipment, years
ended December 31, 1993, 1992 and 1991
All other schedules are omitted as the required information is
inapplicable or the required information is included in the financial
statements or related notes.
Balance Sheets
Assets
December 31,
1993 1992
(Dollars in thousands)
Utility plant:
Electric plant, at cost (note 6) $ 374,736 $ 362,278
Less accumulated depreciation 198,389 185,263
176,347 177,015
Construction work in progress 597 6,408
Net electric plant 176,944 183,423
Nuclear fuel, at cost (note 6):
Assemblies in reactor 69,063 74,025
Fuel in process - 5,236
Spent fuel 287,700 259,199
356,763 338,460
Less accumulated amortization of
burned nuclear fuel 317,039 302,362
39,724 36,098
Less accumulated amortization of
final core nuclear fuel 7,220 6,487
Net nuclear fuel 32,504 29,611
Net utility plant 209,448 213,034
Current assets:
Cash and temporary investments 2,349 1,922
Accounts receivable from sponsors 12,235 15,407
Other accounts receivable 4,522 2,715
Materials and supplies 17,081 16,862
Prepaid expenses 3,949 4,381
Total current assets 40,136 41,287
Deferred charges:
Deferred decommissioning costs
(note 2) 34,379 34,389
Accumulated deferred income taxes
(note 10) 18,231 10,378
Deferred DOE enrichment site
decontamination and
decommissioning fee (note 4) 18,627 18,143
Net unamortized loss on reacquired debt 2,942 -
Other deferred charges (note 4) 3,643 4,994
Total deferred charges 77,822 67,904
Long-term funds at amortized cost:
Decommissioning fund
(notes 2, 5, and 7) 98,880 82,091
Disposal fee defeasance fund
(notes 5, 7, and 8) 43,484 33,892
Total long-term funds 142,364 115,983
$469,770 $438,208
See accompanying notes to financial statements.
Balance Sheets
Capitalization and Liabilities
December 31,
1993 1992
(Dollars in thousands)
Capitalization:
Common stock equity:
Common stock, $100 par value; authorized
400,100 shares; issued 400,014 shares of
which 7,533 are held in Treasury $ 40,001 $ 40,001
Additional paid-in capital 14,227 14,227
Treasury stock (7,533 shares at cost) (1,131) (1,131)
Retained earnings 1,067 1,178
Total common stock equity 54,164 54,275
Long-term obligations, net
(notes 6 and 7) 79,636 74,193
Total capitalization 133,800 128,468
Commitments and contingencies
(notes 2, 14 and 15)
Disposal fee and accrued interest
for spent nuclear fuel (notes 7 and 8) 80,688 78,239
Current liabilities:
Accrued liabilities 28,063 22,743
Accounts payable 2,117 2,591
Accrued interest 635 974
Accrued taxes 1,206 1,472
Total current liabilities 32,021 27,780
Deferred credits:
Accrued decommissioning costs (note 2) 134,614 117,601
Accumulated deferred income taxes 56,478 58,963
Net regulatory tax liability (note 10) 8,351 -
Accumulated deferred investment
tax credits 7,013 7,590
Net unamortized gain on reacquired debt - 1,732
Accrued DOE enrichment
site decontamination and
decommissioning fee (note 4) 15,966 17,220
Other deferred credits 839 615
Total deferred credits 223,261 203,721
$469,770 $438,208
See accompanying notes to financial statements.
Statements of Income and Retained Earnings
Years ended December 31,
1993 1992 1991
(Dollars in thousands
except per share amounts)
Operating revenues $180,145 $175,919 $151,722
Operating expenses:
Nuclear fuel expense 19,526 21,240 24,864
Other operating expense 74,013 72,967 59,666
Maintenance 31,405 27,878 13,664
Depreciation 13,707 13,253 11,800
Decommissioning expense (note 2) 11,315 10,649 8,065
Taxes on income (note 10) 3,777 3,401 3,485
Property and other taxes 9,961 10,227 10,294
Total operating expenses 163,704 159,615 131,838
Operating income 16,441 16,304 19,884
Other income and (deductions):
Net earnings on decommissioning
fund (notes 2 and 5) 5,653 5,395 4,423
Decommissioning expense (note 2) (5,653) (5,395) (4,423)
Allowance for equity funds used
during construction 92 89 124
Interest 1,550 2,046 1,377
Taxes on other income (note 10) (623) (756) (447)
Other, net (232) (199) (917)
787 1,180 137
Income before interest expense 17,228 17,484 20,021
Interest expense:
Interest on long-term debt 7,281 7,101 7,684
Interest on disposal costs of
spent nuclear fuel (note 8) 2,450 2,801 4,312
Allowance for borrowed funds used
during construction (297) (339) (465)
Total interest expense 9,434 9,563 11,531
Net income 7,794 7,921 8,490
Retained earnings at beginning
of year 1,178 1,166 1,982
8,972 9,087 10,472
Dividends declared 7,905 7,909 9,306
Retained earnings at end of year $ 1,067 $ 1,178 $ 1,166
Average number of shares
outstanding in thousands 392 392 394
Net income per average share
of common stock outstanding $ 19.86 $ 20.18 $ 21.56
Dividends per average share of common stock outstanding $
20.14 $ 20.15 $ 23.71
See accompanying notes to financial statements.
Statements of Cash Flows
Years ended December 31,
1993 1992 1991
(Dollars in thousands)
Cash flows from operating activities:
Net income $7,794 $ 7,921 $ 8,490
Adjustments to reconcile net
income to net cash provided
by operating activities:
Amortization of nuclear fuel 15,410 18,143 21,002
Depreciation 13,707 13,253 11,800
Decommissioning expense 11,315 10,649 8,065
Deferred tax expense (979) (2,169) (801)
Amortization of deferred
investment tax credits (577) (641) (740)
Nuclear fuel disposal fee
interest accrual 2,450 2,802 4,312
Interest and dividends on
disposal fee defeasance fund (1,402) (1,385) (1,495)
(Increase) decrease in
accounts receivable 1,365 688 (129)
(Increase) decrease in prepaid
expenses 432 (1,159) 163
(Increase) in materials and
supplies inventory (219) (454) (1,531)
Increase (decrease) in accounts
payable and accrued liabilities 4,846 (7,453) 5,495
Increase (decrease) in interest
and taxes payable (605) 306 (760)
Other (1,228) (1,410) (1,665)
Total adjustments 44,515 31,170 43,716
Net cash provided by
operating activities 52,309 39,091 52,206
Cash flows from investing activities:
Electric plant additions (7,229) (10,750) (6,596)
Nuclear fuel additions (18,303) (4,707) (18,444)
Payments to decommissioning fund (11,250) (10,612) (8,323)
Payments to disposal fee
defeasance fund (8,190) (5,190) (8,216)
Net cash used in investing
activities (44,972) (31,259) (41,579)
Cash flows from financing activities:
Dividend payments (7,905) (7,909) (9,306)
Purchase of treasury stock - - (1,131)
Issuance of Series H first
mortgage bonds, net - - 10,374
Issuance of Series I first
mortgage bonds, net 75,125 - -
Retirement of first mortgage bonds
including redemption costs (74,629) (6,521) (13,178)
Payments of long-term obligations (137,911) (107,763) (53,419)
Borrowings under long-term
agreements 138,410 111,215 53,798
Net cash used in financing
activities (6,910) (10,978) (12,862)
Net increase (decrease) in cash and
temporary investments 427 (3,146) (2,235)
Cash and temporary investments at
beginning of year 1,922 5,068 7,303
Cash and temporary investments
at end of year $ 2,349 $ 1,922 $ 5,068
See accompanying notes to financial statements.
Notes to Financial Statements
NOTE 1. Summary of Significant Accounting Policies
(a) Regulations and Operations
Vermont Yankee Nuclear Power Corporation ("the Company") is subject to
regulations prescribed by the Federal Energy Regulatory Commission
("FERC"), and the Public Service Board of the State of Vermont with
respect to accounting and other matters. The Company is also subject to
regulation by the Nuclear Regulatory Commission ("NRC") for nuclear plant
licensing and safety, and by federal and state agencies for environmental
matters such as air quality, water quality and land use.
Prior to November, 1993, the Company was subject to regulation by the
Securities and Exchange Commission. As a result of the debt refinancing
discussed in note 6, the Company is no longer subject to such regulation.
The Company recognizes revenue pursuant to the terms of the Power
Contracts and Additional Power Contracts. The Sponsors, a group of nine
New England utilities, are severally obligated to pay the Company each
month their entitlement percentage of amounts equal to the Company's total
fuel costs and operating expenses of its Plant, plus an allowed return on
equity (since December 1, 1989, 12.25%). Such contracts also obligate the
Sponsors to make decommissioning payments through the end of the Plant's
service life and the completion of the decommissioning of the Plant. All
Sponsors are committed to such payments regardless of the Plant's
operating level or whether the Plant is out of service during the period.
Under the terms of the Capital Funds Agreements, the Sponsors are
committed, subject to obtaining necessary regulatory authorizations, to
make funds available to obtain or maintain licenses necessary to keep the
Plant in operation.
(b) Depreciation and Maintenance
Electric plant is being depreciated on the straight-line method at rates
designed to fully depreciate all depreciable properties over the lesser of
estimated useful lives or the Plant's remaining NRC license life, which
extends to March, 2012. Depreciation expense was equivalent to overall
effective rates of 3.74%, 3.56% and 3.23% for the years 1993, 1992 and
1991, respectively.
Renewals and betterments constituting retirement units are charged to
electric plant. Minor renewals and betterments are charged to maintenance
expense. When properties are retired, the original cost, plus cost of
removal, less salvage, is charged to the accumulated provision for
depreciation.
(c) Amortization of Nuclear Fuel
The cost of nuclear fuel is amortized to expense based on the rate of
burn-up of the individual assemblies comprising the total core. The
Company also provides for the costs of disposing of spent nuclear fuel at
rates specified by the United States Department of Energy ("DOE") under a
contract for disposal between the Company and the DOE.
The Company amortizes to expense on a straight-line basis the estimated
costs of the final unspent nuclear fuel core, which is expected to be in
place at the expiration of the Plant's NRC operating license in conformity
with rates authorized by the FERC.
(d) Amortization of Materials and Supplies
The Company amortizes to expense a formula amount designed to fully
amortize the cost of the material and supplies inventory that is expected
to be on hand at the expiration of the Plant's NRC operating license.
(e) Long-term Funds
The Company accounts for its investments in long-term funds at amortized
cost since it has both the intent and ability to hold these investments
for the foreseeable future. Amortized cost represents the cost to
purchase the investment, net of any unamortized premiums or discounts.
Notes to Financial Statements
NOTE 1. Summary of Significant Accounting Policies (Continued)
(f) Amortization of Gain and Loss on Reacquired Debt
The difference between the amount paid upon reacquisition of any debt
security and the face value thereof, plus any unamortized premium, less
any related unamortized debt expense and reacquisition costs, or less any
unamortized discount, related unamortized debt expense and reacquisition
costs applicable to the debt redeemed, retired and canceled, is deferred
by the Company and amortized to expense on a straight-line basis over the
remaining life of the applicable security issues.
(g) Allowance for Funds Used During Construction
Allowance for funds used during construction ("AFUDC") is the estimated
cost of funds used to finance the Company's construction work in progress
and nuclear fuel in process which is not recovered from the Sponsors
through current revenues. The allowance is not realized in cash
currently, but under the Power Contracts, the allowance will be recovered
in cash over the Plant's service life through higher revenues associated
with higher depreciation and amortization expense.
AFUDC was capitalized at overall effective rates of 5.92%, 6.82% and 6.98%
for 1993, 1992 and 1991, respectively, using the gross rate method.
(h) Decommissioning
The Company is accruing the estimated costs of decommissioning its Plant
over the Plant's remaining NRC license life. Any amendments to these
estimated costs are accounted for prospectively.
(i) Taxes on Income
Effective January 1, 1993, the Company began accounting for taxes on
income under the liability method required by Statement of Financial
Accounting Standard 109. See Note 10 for a further discussion of this
change in accounting.
Investment tax credits have been deferred and are being amortized to
income over the lives of the related assets.
(j) Cash Equivalents
For purposes of the Statements of Cash Flows, the Company considers all
highly liquid short-term investments with an original maturity of three
months or less to be cash equivalents.
(k) Reclassifications
Certain information in the 1992 and 1991 financial statements has been
reclassified to conform with the 1993 presentation.
(l) Earnings per Common Share
Earnings per common share have been computed by dividing earnings
available to common stock by the weighted average number of shares
outstanding during the year.
Notes to Financial Statements
NOTE 2. Decommissioning
The Company accrues estimated decommissioning costs for its nuclear plant
over its remaining NRC licensed life based on studies by an independent
engineering firm that assumes that decommissioning will be accomplished by
the prompt removal and dismantling method. This method requires that
radioactive materials be removed from the plant site and that all
buildings and facilities be dismantled immediately after shutdown.
Studies estimate that approximately six years would be required to
dismantle the Plant at shutdown, remove wastes and restore the site. The
Company has implemented rates based on a settlement agreement with the
FERC which allowed $190 million, in 1988 dollars, as the estimated
decommissioning cost. This allowed amount is used to compute the
Company's liability and billings to the Sponsors. Based on an assumed
inflation rate of 6% per annum and an expiration of the Plant's NRC
operating license in 2012, the estimated current cost of decommissioning
is $253 million and, at the end of 2012, is approximately $769 million.
The present value of the pro rata portion of decommissioning costs
recorded to date is $134.6 million. On December 31, 1993, the balance in
the Decommissioning Trust was $98.9 million.
Billings to Sponsors for estimated decommissioning costs commenced during
1983, at which time the Company recorded a deferred charge for the present
value of decommissioning costs applicable to operations of the Plant for
prior periods. Current period decommissioning costs not funded through
billings to Sponsors or earnings on decommissioning fund assets are also
deferred. These deferred costs will be amortized to expense as they are
funded over the remaining life of the NRC operating license.
In 1994, the Company must file a revised estimate of decommissioning costs
and a revised schedule of future annual decommissioning fund collections
reflecting the historical differences between assumed and actual rates of
inflation and the historical differences between assumed and actual rates
of earnings on decommissioning fund assets. Filings are required to be
made within four years of the most recent FERC approval of decommissioning
cost estimates and rates.
Cash received from Sponsors for plant decommissioning costs is deposited
into the Vermont Yankee Decommissioning Trust in either the Qualified Fund
(i.e., amounts currently deductible pursuant to the IRS regulations) or
the Nonqualified Fund (i.e., excess collections pursuant to FERC
authorization which are not currently deductible). Funds held by the
Trust are invested in high-grade U.S. government securities and municipal
obligations. Interest earned by the Decommissioning Trust assets is
recorded in other income and deductions, with an equal and offsetting
amount representing the current period decommissioning cost funded by such
earnings reflected as decommissioning expense.
Decommissioning expense for 1991 included an adjustment of approximately
$2.1 million resulting from the Company's rate reduction filing approved
by the FERC on February 28, 1991 as discussed in Note 3.
NOTE 3. FERC Rate Case Matters
On April 27, 1989, Vermont Yankee filed an application with the NRC to
extend the term of the operating license from 2007 to 2012 so that the
Plant may operate for 40 years after it entered commercial service in
1972. On December 17, 1990, the NRC issued an amendment to the operating
license extending its term to March 21, 2012. The Company submitted a
rate reduction filing with the FERC to reflect in rates the adjustments to
decommissioning, depreciation and amortization resulting from the license
extension. The Company proposed to make this reduction effective as of
March 1, 1991 and, since the extension was issued in 1990, to reflect the
necessary adjustment for the period January 1, 1990 through February 28,
1991.
On February 28, 1991, the FERC approved the Company's rate reduction
filing. The effects of this ruling were accounted for prospectively in
fiscal 1991, producing a net revenue reduction of approximately $7.4
million in 1991, which reflected the retroactive treatment to January 1,
1990. This ruling resulted in reduced revenue requirements of
approximately $3.5 million for both 1992 and 1993, and similar reductions
are expected in future years.
Notes to Financial Statements
NOTE 3. FERC Rate Case Matters (Continued)
On March 26, 1993, the FERC initiated a review of the return on common
equity component of the formula rates included in the Company's Power
Contracts. On October 22, 1993, the FERC approved a settlement whereby
the Company retained its 12.25% authorized rate of return on common equity
and agreed to credit monthly power billings by approximately $139,000
beginning in June, 1993.
In 1994, the Company will submit a rate filing to the FERC which will
include, among other things, a revised estimate of decommissioning costs
and a revised schedule of future annual decommissioning fund collections.
NOTE 4. Other Deferred Charges and Credits
In October, 1992, Congress passed the Energy Policy Act of 1992 which
requires, among other things, that certain utilities help pay for the
cleanup of the DOE's enrichment facilities over a 15-year period. The
Company's annual fee is estimated based on the historical share of
enrichment service provided by the DOE and is indexed to inflation. These
fees will not be adjusted for future business as the DOE's future cost of
sales will include a decontamination and decommissioning component. The
Act stipulates that the annual fee shall be fully recoverable in rates in
the same manner as other fuel costs.
In 1993, the DOE billed and the Company paid the first of the 15 annual
fees. As of December 31, 1993, the Company has recognized a current
accrued liability of $2.6 million for the two fee payments expected to be
made in 1994, a deferred credit of $16.0 million for the 12 annual fee
payments that are due subsequent to 1994 and a corresponding regulatory
asset of $18.6 million which represents the total amount includable in
future billings to the purchasers under the Power Contracts. While these
amounts are reflected in these financial statements, the Company is
reviewing the DOE's calculation of the annual fee and believes that the
annual fee will ultimately be reduced.
Approximately $2.1 and $3.3 million of the $3.6 and $5.0 million in other
deferred charges at December 31, 1993 and 1992, respectively, relate to
payments made to the Vermont Low Level Radioactive Waste Authority
("VLLRWA"), an agency of the State of Vermont for the siting and
construction of a low-level waste disposal facility.
NOTE 5. Long-term Funds
The book value and estimated market value of long-term fund investment
securities at December 31, is as follows:
1993 1992
Book Market Book Market
value value value value
(Dollars in thousands)
Decommissioning fund:
U.S. Treasury obligations $17,262 18,666 $22,000 $23,067
Municipal obligations 79,755 84,576 57,141 59,009
Accrued interest and
money market funds 1,863 1,863 2,950 2,950
98,880 105,105 82,091 85,026
Disposal fee defeasance fund:
Short-term investments 39,870 39,870 26,457 26,457
Corporate bonds and notes 3,195 3,083 6,110 5,940
Accrued interest and
money market funds 419 419 1,325 1,325
43,484 43,372 33,892 33,722
Total long-term
fund investments $142,364 $148,477 $115,983 $118,748
Notes to Financial Statements
NOTE 5. Long-term Funds (Continued)
At December 31, 1993 and 1992, gross unrealized gains and losses
pertaining to the long-term investment securities were as follows:
1993 1992
(Dollars in thousands)
Unrealized gains on U.S. Treasury obligations $ 1,431 $ 1,071
Unrealized losses on U.S. Treasury obligations $ (27) $ (4)
Unrealized gains on Municipal obligations $ 4,843 $ 1,895
Unrealized losses on Municipal obligations $ (22) $ (27)
Unrealized losses on corporate bonds and notes $ (112) $ (170)
Maturities of short-term obligations, bonds and notes (face amount) at
December 31, 1993 are as follows (dollars in thousands):
Within one year $42,200
Two to five years 16,977
Five to seven years 19,670
Over seven years 57,860
$136,707
NOTE 6. Long-term Obligations
A summary of long-term obligations at December 31, 1993 and 1992 is as
follows:
1993 1992
(Dollars in thousands)
First mortgage bonds:
Series B - 8.50% due 1998 $ - $1,307
Series C - 7.70% due 1998 - 1,612
Series D - 10.125% due 2007 - 23,147
Series E - 9.875% due 2007 - 5,703
Series F - 9.375% due 2007 - 5,704
Series G - 8.94% due 1995 - 25,000
Series H - 8.25% due 1996 - 8,388
Series I - 6.48% due 2009 75,845 -
Total first mortgage bonds 75,845 70,861
Eurodollar Agreement Commercial Paper 3,791 3,292
Unamortized premium on debt - 40
Total long-term obligations $ 79,636 $ 74,193
The first mortgage bonds are issued under, have the terms and provisions
set forth in, and are secured by an Indenture of Mortgage dated as of
October 1, 1970 between the Company and the Trustee, as modified and
supplemented by 13 supplemental indentures. All bonds are secured by a
first lien on utility plant, exclusive of nuclear fuel, and a pledge of
the Power Contracts and the Additional Power Contracts (except for fuel
payments) and the Capital Funds Agreements with Sponsors.
On July 1, 1993, the Company retired the outstanding Series B and Series
C first mortgage bonds. In November, 1993, the Company issued $75.8
million of Series I, first mortgage bonds stated to mature on November 1,
2009. The Company applied the proceeds of the bond issuance principally
to retire the remaining Series D, Series E, Series F, Series G and Series
H first mortgage bonds including call premiums totalling $3.7 million
based on the early redemption of the bonds. Cash sinking fund
requirements for the Series I first mortgage bonds are $5.4 million
annually beginning in November, 1999.
The Company has a $75.0 million Eurodollar Credit Agreement that expires
on December 31, 1995 subject to three optional one-year extensions. The
Company issued commercial paper under this agreement with weighted average
interest rates of 3.22% for 1993 and 3.95% for 1992. Payment of the
commercial paper is supported by the Eurodollar Credit Agreement, which is
secured by a second mortgage on the Company's generating facility.
Notes to Financial Statements
NOTE 7. Disclosures About the Fair Value of Financial Instruments
The carrying amounts for cash and temporary investments, trade
receivables, accounts receivable from sponsors, accounts payable and
accrued liabilities approximate their fair values because of the short
maturity of these instruments. The fair values of long-term funds are
estimated based on quoted market prices for these or similar investments.
The fair values of each of the Company's long-term debt instruments are
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 maturities.
The estimated fair value of the Company's financial instruments as of
December 31 are summarized as follows (dollars in thousands):
1993 1992
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
Decommissioning fund $98,880 $105,105 $82,091 $85,026
Disposal fee
defeasance fund 43,484 43,372 33,892 33,722
Long-term debt 79,636 77,361 74,193 78,235
Disposal fee and
accrued interest 80,688 80,688 78,239 78,239
Fair value estimates are made at a specific point in time, based on
relevant market information and information about the financial
instrument. These estimates are subjective in nature and involve
uncertainties and matters of significant judgment and therefore cannot be
determined with precision. Changes in assumptions could significantly
affect the estimates.
NOTE 8. Disposal Fee for Spent Nuclear Fuel
The Company 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 1 mil 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
current statute to be prior to January 31, 1998.
The DOE contract obligates the Company to pay a one-time fee of
approximately $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, the Company 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 1993, the Company
deposited approximately $37.5 in an irrevocable trust to be used
exclusively for defeasing this obligation at some future date, provided
the DOE complies with the terms of the aforementioned contract.
On December 31, 1991, the DOE issued an amended final rule modifying the
Standard Contract for Disposal of Spent Nuclear Fuel and/or High-level
Radioactive Waste. The amended final rule conforms with a March 17, 1989
ruling of the U.S. Court of Appeals for the District of Columbia that the
1 mil per kilowatt hour fee in the Standard Contract should be based on
net electricity generated and sold. The impact of the amendment on the
Company was to reduce the basis for the fee by 6% on an ongoing basis and
to establish a receivable from the DOE for previous overbillings and
accrued interest. The Company has recognized in its rates the full impact
of the amended final rule to the Standard Contract.
The DOE is refunding the overpayments, including interest, to utilities
over a four-year period ending in 1995 via credits against quarterly
payments. Interest is based on the 90-day Treasury Bill Auction Bond
Equivalent and will continue to accrue on amounts remaining to be
credited. At December 31, 1993 and 1992, respectively, approximately $0.9
and $1.6 million in principal and interest is reflected in other accounts
receivable.
Notes to Financial Statements
NOTE 9. Short-term Borrowings
The Company had lines of credit from various banks totalling $6.3 million
at December 31, 1993 and 1992. The maximum amount of short-term
borrowings outstanding at any month-end during 1993, 1992 and 1991 was
approximately $0.2 million, $0.6 million and $0.4 million, respectively.
The average daily amount of short-term borrowings outstanding was
approximately $0.3 million for 1993, and $0.1 million for 1992 and 1991
with weighted average interest rates of 5.75% in 1993, 6.12 % in 1992 and
8.19% in 1991. There were no amounts outstanding under these lines of
credit as of December 31, 1993 and 1992.
NOTE 10. Taxes on Income
In February, 1992, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 109, "Accounting for
Income Taxes", which required the Company to change from the deferred
method to the liability method of accounting for income taxes on January
1, 1993. The liability method accounts for deferred income taxes by
applying enacted statutory rates in effect at the balance sheet date to
differences between the book basis and the tax basis of assets and
liabilities ("temporary differences").
This new statement requires recognition of deferred tax liabilities for
(a) income tax benefits associated with timing differences previously
passed on to customers and (b) the equity component of allowance for funds
used during construction, and of a deferred tax asset for the tax effect
of the accumulated deferred investment tax credits. It also requires the
adjustment of deferred tax liabilities or assets for an enacted change in
tax laws or rates, among other things.
Although adoption of this new statement has not and is not expected to
have a material impact on the Company's cash flow, results of operations
or financial position because of the effect of rate regulation, the
Company was required to recognize an adjustment to accumulated deferred
income taxes and a corresponding regulatory asset or liability to
customers (in amounts equal to the required deferred income tax
adjustment) to reflect the future revenues or reduction in revenues that
will be required when the temporary differences turn around and are
recovered or settled in rates. In addition, this new statement required
a reclassification of certain deferred income tax liabilities to
liabilities to customers in order to reflect the Company's obligation to
flow back deferred income taxes provided at rates higher than the current
35% federal tax rate. The Company has applied the provisions of this new
statement without restating prior year financial statements.
The components of income tax expense for the years ended December 31,
1993, 1992 and 1991 are as follows:
1993 1992 1991
(Dollars in thousands)
Taxes on operating income:
Current federal income tax $ 4,236 $ 4,926 $ 4,003
Deferred federal income tax (1,059) (1,840) (1,285)
Current state income tax 1,097 1,285 1,024
Deferred state income tax 80 (329) 483
Investment tax credit
adjustment (577) (641) (740)
3,777 3,401 3,485
Taxes on other income:
Current federal income tax 496 598 353
Current state income tax 127 158 94
623 756 447
Total income taxes $ 4,400 $ 4,157 $ 3,932
Notes to Financial Statements
NOTE 10. Taxes on Income (Continued)
A reconciliation of the Company's effective income tax rates with the
federal statutory rate is as follows:
1993 1992 1991
Federal statutory rate 35.0% 34.0% 34.0%
State income taxes, net of
federal income tax benefit 6.9 6.1 6.1
Investment credit (4.7) (5.3) (6.0)
Book depreciation in
excess of tax basis 2.0 1.9 1.7
AFUDC equity 0.6 0.9 0.9
Flowback of excess
deferred taxes (3.6) (3.1) (6.7)
Other (0.1) (0.1) 1.7
36.1% 34.4% 31.7%
The items comprising deferred income
tax expense are as follows:
1993 1992 1991
(Dollars in thousands)
Decommissioning expense not
currently deductible $ (351) $ (104) $ 14
Tax depreciation over (under)
financial statement
depreciation (978) (679) 955
Tax fuel amortization
over (under) financial
statement amortization (255) (637) (1,389)
Tax loss on reacquisition of debt
over (under) financial
statement expense 1,887 187 178
Pension expense not
currently deductible (167) (192) (562)
Postemployment benefits deduction
over (under) financial
statement expense 67 (141) -
Amortization of materials and
supplies not currently deductible (335) (343) (239)
Low-level waste deduction
over (under) financial
statement expense (596) 139 825
Flowback of excess
deferred taxes (442) (376) (828)
Other 191 (23) 245
$ (979) $ (2,169) $ (801)
Notes to Financial Statements
NOTE 10. Taxes on Income (Continued)
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at
December 31, 1993 and January 1, 1993 are presented below:
December 31, January 1,
1993 1993
(Dollars in thousands)
Deferred tax assets:
Accumulated amortization of
final nuclear core $ 2,914 $ 2,559
Nuclear decommissioning liability 2,810 2,291
Regulatory liabilities 5,856 6,793
Accumulated deferred investment credit 2,830 2,984
Accumulated amortization of
materials and supplies 2,281 1,851
Other 2,771 4,591
Total gross deferred tax assets 19,462 21,069
Less valuation allowance 1,231 1,142
Net deferred tax assets 18,231 19,927
Deferred tax liabilities:
Plant and equipment (51,258) (51,399)
Other (5,220) (5,574)
Total gross deferred tax liabilities (56,478) (56,973)
Net deferred tax liability (38,247) (37,046)
The valuation allowance is the result of a provision in Vermont tax law
which limits refunds resulting from carrybacks of net operating losses.
NOTE 11. Supplemental Cash Flow Information
The following information supplements the cash flow information provided
in the Statements of Cash Flows:
1993 1992 1991
(Dollars in thousands)
Cash paid during the year for:
Interest (net of amount
capitalized) $ 7,632 $ 7,062 $ 7,990
Income taxes $ 7,070 $ 6,192 $ 4,793
NOTE 12. Pension Plans
The Company has two noncontributory pension plans covering substantially
all of its regular employees. The Company's funding policy is to fund the
net periodic pension expense accrued each year. Benefits are based on
age, years of service and the level of compensation during the final years
of employment.
The aggregate funded status of the Company's pension plans as of December
31, 1993 and 1992 is as follows:
December 31,
1993 1992
(Dollars in thousands)
Vested benefits $ 8,882 $ 6,548
Nonvested benefits 1,338 918
Accumulated benefit obligation 10,220 7,466
Additional benefits related to
future compensation levels 8,540 7,728
Projected benefit obligation 18,760 15,194
Fair value of plan assets, invested
primarily in equities and bonds 16,343 13,791
Projected benefit obligation in
excess of plan assets $ 2,417 $ 1,403
Notes to Financial Statements
NOTE 12. Pension Plans (Continued)
The increase in the projected benefit obligation from $15.2 million in
1992 to $18.8 million in 1993 is the result of additional service
accruals, interest costs and changed plan assumptions.
Certain changes in the items shown above are not recognized as they occur,
but are amortized systematically over subsequent periods. Unrecognized
amounts still to be amortized and the amount that is included in the
balance sheet appear below.
December 31,
1993 1992
(Dollars in thousands)
Unrecognized net transition obligation $ 996 $1,057
Unrecognized net gain (4,086) (4,939)
Pension liability included
in balance sheet 4,866 4,610
Unrecognized prior service costs 641 675
Projected benefit obligation in excess of
plan assets $ 2,417 $ 1,403
The following are pension plan assumptions as of December 31, 1993 and 1992:
December 31,
1993 1992
Discount rate 7.0% 8.0%
Compensation scale 5.5% 6.5%
Expected return on assets 8.5% 8.5%
Net pension expense for the three years ending December 31, 1993 included the
following components:
1993 1992 1991
(Dollars in thousands)
Service cost - benefits earned $ 1,141 $ 1,275 $ 1,147
Interest cost on projected
benefit obligation 1,288 1,305 1,104
Actual (return) loss
on plan assets (1,792) (867) (2,124)
Net amortization and deferral 631 78 1,452
Net pension expense $ 1,268 $ 1,791 $ 1,579
NOTE 13. Postretirement Benefits Other Than Pensions
The Company adopted Statement of Financial Accounting Standards No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions"
(SFAS 106), on January 1, 1992. This statement requires companies to use
accrual accounting for postretirement benefits other than pensions. Prior
to 1992, the Company accrued and collected a portion of postretirement
benefits costs through decommissioning billings while the remaining cost
was expensed when benefits were paid. The incremental cost, above the
amount collected through decommissioning billings, approximately $2.4
million, is now accrued and since January, 1992, has been included in the
Company's monthly power billings to Sponsors. The Company is funding this
liability by placing monies in separate trusts. In order to maximize the
deductible contributions permitted under IRS regulations, the Company has
amended its pension plans and established separate VEBA trusts for
management and union employees.
Notes to Financial Statements
NOTE 13. Postretirement Benefits Other Than Pensions (Continued)
In December, 1992, the FERC issued its policy statement setting forth how
utilities can recover in rates the increased costs associated with the
implementation of SFAS 106. The policy statement specifies three
conditions that must be met before FERC will consider companies' election
of the accrual method: (a) the Company must agree to make cash deposits to
an irrevocable external trust fund, at least quarterly, in amounts that
are proportional and, on an annual basis, equal to the annual test period
allowance for postretirement benefits other than pensions; (b) the Company
must agree to maximize the use of income tax deductions for contributions
to funds of this nature; and (c) in order to recover the transition
obligation, the Company must file a general rate change within three years
of adoption of SFAS 106.
The following table presents the plan's funded status reconciled with
amounts recognized in the Company's balance sheets as of December 31, 1993
and December 31, 1992 (dollars in thousands):
Accumulated postretirement benefit obligation:
1993 1992
Retirees $ 1,078 $ 1,277
Fully eligible active plan participants 921 1,332
Other active participants 8,071 9,935
Total accumulated postretirement
benefit obligation 10,070 12,544
Fair value of plan assets, invested
primarily in short-term investments 2,457 1,595
Accumulated postretirement benefit
obligation in excess of plan assets $ 7,613 $10,949
Unrecognized net transition obligation $ 7,933 $10,314
Unrecognized net gain (1,980) (126)
Accrued postretirement benefit cost
collected through decommissioning
billings and included in
accrued liabilities 1,660 761
Accumulated postretirement benefit
obligation in excess of plan assets $ 7,613 $ 10,949
The net periodic postretirement benefit cost for 1993 and 1992 includes
the following components (dollars in thousands):
1993 1992
Service cost $ 735 $ 958
Interest cost 652 941
Net amortization and deferral 350 543
Net periodic postretirement benefit cost $ 1,737 $2,442
For measurement purposes, a 15% annual rate of increase in the per capita
cost of covered benefits (i.e., health care cost trend rate) was assumed
for 1993; the rate was assumed to decrease gradually to 6% by the year
2001 and remain at that level thereafter. The health care cost trend rate
assumption has a significant effect on the amounts reported. For example,
increasing the assumed health care cost trend rates by one percentage
point in each year would increase the accumulated postretirement benefit
obligation as of December 31, 1993 by $2.2 million and the aggregate of
the service and interest cost components of net periodic postretirement
benefit cost for the year ended December 31, 1993 by $0.3 million. The
weighted-average discount rate used in determining the accumulated
postretirement benefit obligation was 7% at December 31, 1993.
The change in the accumulated postretirement benefit obligation from $12.5
million in 1992 to $10.0 million in 1993 is the result of adjustments made
to reflect a lower actual medical cost increase during 1993 than
projected. The reduction in the unrecognized net transition obligation
from $10.3 million in 1992 to $7.9 million in 1993 is primarily the result
of elimination of Medicare Part B coverage.
Notes to Financial Statements
NOTE 14. Lease Commitments
The Company leases equipment and systems under noncancelable operating
leases. Charges against income for rentals under these leases were
approximately $3.7 million, $2.6 million and $3.7 million in 1993, 1992
and 1991, respectively. Minimum future rentals as of December 31, 1993
are as follows:
Annual
Fiscal years ended rentals
(Dollars in thousands)
1994 $ 3,283
1995 3,060
1996 2,878
1997 2,798
1998 and after 5,053
The Company has entered into an agreement with General Electric Capital
Corporation to lease certain equipment being constructed by General
Electric Corporation valued at approximately $29 million including
installation costs. Under the lease agreement, the Company will make 120
monthly payments of $342,358 per month commencing on the later of (1)
April 15, 1995 or (2) the commissioning date of the equipment. The lease
will also include the sale and leaseback of a $2 million turbine rotor
forging previously owned by the Company. The lease will be classified as
an operating lease for accounting purposes.
The construction contract requires progress payments to be paid by Vermont
Yankee prior to installation of the equipment. Just prior to delivery of
the equipment, the lessor will reimburse Vermont Yankee for these payments
and will continue to make the remaining payments until the commencement
date of the lease. During the time period subsequent to equipment
delivery before the equipment is commissioned, the Company will pay
interim rent to the lessor based on the amount of outstanding progress
payments. The final documentation of the lease is currently being
negotiated, and if a final agreement cannot be reached, the Company would
be responsible for substantial termination payments.
Low-level Waste
In February, 1993, the Vermont Public Service Board issued an order which
requires the Company to pay its share of expenses incurred by the Vermont
Low Level Radioactive Waste Authority for the period April, 1993 through
June, 1994, currently capped at $4.5 million. In addition, in accordance
with Vermont Act 296, the order established a fund for the long-term care
of any eventual Vermont low-level waste disposal facility. Based on this
order, the Company must make annual payments of approximately $0.8 million
into the long-term care fund. Payments made to the VLLRWA, not pertaining
directly to the siting and construction of a low-level waste disposal
facility, are being expensed currently.
In parallel with siting a low-level radioactive waste facility in Vermont,
there has been a three-state effort between Vermont, Maine, and Texas to
form a compact to site such a facility in Texas. The Texas Legislature
has approved, and Governor Ann Richards of Texas has signed into law, a
bill that would form such a compact. On November 2, 1993, Maine voters
ratified the compact. Early during its 1994 session, the Vermont
Legislature is scheduled to vote to approve entry into the compact.
Following approval by the Vermont Legislature, the compact will require
approval of the U.S. Congress.
Notes to Financial Statements
NOTE 15. Commitments and Contingencies (Continued)
If the compact is successful and proceeds on schedule, Vermont Yankee
would begin sending its waste to a Texas facility during 1997. Under the
proposed compact, Vermont would pay the State of Texas $25 million ($12.5
million when the U.S. Congress ratifies the compact and $12.5 million when
the facility opens). In addition, Vermont must pay $2.5 million ($1.25
million when Congress ratifies the compact and $1.25 million when the
facility is licensed) for community assistance projects in Hudspeth
County, Texas, where the facility is to be located. Vermont would also
pay one-third of the Texas Low-Level Radioactive Waste Disposal Compact
Commission's expenses until the facility opens. The Disposal fees for
generators in Vermont and Maine would then be set at a level that is the
same for generators in Texas. The Company anticipates recovering the
costs of the compact from sponsors.
Nuclear Fuel
The Company has approximately $165 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 the Company to cancel or
postpone deliveries until actually needed.
Insurance
The Price-Anderson Act, as amended, currently limits public liability from
a single incident at a nuclear power plant to $9.4 billion. Any damages
beyond $9.4 billion are indemnified under an agreement with the NRC, 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 $9.2 billion per incident by assessing
retrospective premiums of $79.3 million against each of the 116 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 above insurance covers all workers employed at nuclear facilities
prior to January 1, 1988, for bodily injury claims. The Company has
purchased a Master Worker insurance policy with limits of $200 million
with one automatic reinstatement of policy limits to cover workers
employed on or after January 1, 1988. Vermont Yankee's estimated
contingent liability for a retrospective premium on the Master Workers
policy as of December, 1993 is $3.1 million. The Secondary Financial
Protection program referenced above provides coverage in excess of the
Master Worker policy.
Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL
II) to cover the costs of property damage, decontamination or premature
decommissioning resulting from a nuclear incident. All companies insured
with NEIL II are subject to retroactive assessments if losses exceed the
accumulated funds available to NEIL II. The maximum potential assessment
against the Company with respect to losses arising during the current
policy year is $5.8 million at the time of a first loss and $12.3 million
at the time of a subsequent loss. The Company's liability for the
retrospective premium adjustment for any policy year ceases six years
after the end of that policy year unless prior demand has been made.
Notes to Financial Statements
VERMONT YANKEE NUCLEAR POWER CORPORATION
Schedule I
Marketable Securities - Other Investments
(Dollars in Thousands)
__________________________________________________________________________
Name of Issuer and Number Cost of Market Amount
Title of Each Issue of Shares Each Value of at Which
or Units Issue Each Each
Principal * Issue Portfolio
Amounts of at of Equity
Bonds and 12/31/93 Security
Notes Issues
and Each
Other
Security
Issue Is
Carried
on the
Balance
Sheet
__________________________________________________________________________
Decommissioning fund:
U.S. Treasury
obligations $ 16,252 $ 17,262 $ 18,666 $ 17,262
Municipal obligations 78,055 79,755 84,576 79,755
Money market funds and
Accrued Interest 1,863 1,863 1,863 1,863
$ 96,170 $ 98,880 $105,105 $ 98,880
Disposal fee defeasance fund:
Short-term investments $ 40,200 $ 39,870 $ 39,870 $ 39,870
Corporate bonds
and notes 3,200 3,195 3,083 3,195
Money market funds and
Accrued Interest 419 419 419 419
$ 43,819 $ 43,484 $ 43,372 $ 43,484
* Cost includes accrued interest and amortization of premiums and
discounts.
VERMONT YANKEE NUCLEAR POWER CORPORATION
Schedule V - Property, Plant and Equipment
Years Ended December 31, 1993, 1992, and 1991
($000)
1993 1992 1991
Electric Plant:
Land and land rights $ 1,397 $ 1,127 $ 984
Structures and improvements 61,887 61,868 61,515
Reactor, turbogenerator and
accessory equipment 304,388 292,561 285,808
Transmission equipment 5,948 5,606 6,141
Other 1,116 1,116 1,116
Construction work
in progress 597 6,408 4,188
375,333 368,686 359,752
Nuclear Fuel:
Assemblies in reactor 69,063 74,025 83,213
Fuel in process - 5,236 637
Fuel in stock - - 22,863
Spent fuel 287,700 259,199 227,040
356,763 338,460 333,753
Total $732,096 $707,146 $693,505
Neither total additions of $25,361,000, $15,167,000 or $25,002,000 nor
total retirements of $411,000, $1,526,000, or $0 for the years ended
December 31, 1993, 1992 and 1991, respectively, exceeded 10% of the
utility plant balance at the end of the year.
VERMONT YANKEE NUCLEAR POWER CORPORATION
Schedule VI - Accumulated Depreciation, Depletion and
Amortization of Property, Plant and Equipment
Years Ended December 31, 1993, 1992 and 1991
(Dollars in Thousands)
Additions Other
Balance Charged to Charges Balance
Beginning Costs and and At End
of Year Expenses Retirements (Deduct) of Year
Accumulated depreciation of
electric plant: (F1)
1993 185,263 13,707 (411) (170) (B) 198,389
1992 173,827 13,253 (1,526) (291) (B) 185,263
1991 162,065 11,800 - ( 38) (B) 173,827
Accumulated amortization of
nuclear fuel:
1993 308,848 19,526 - (4,115) (C) 324,259
1992 291,013 21,240 - (3,405) (C) 308,848
1991 270,011 24,864 - (3,862) (C) 291,013
Total accumulated depreciation
and amortization
1993 494,111 33,234 (411) (4,286) 522,648
1992 464,840 34,493 (1,526) (3,696) 494,111
1991 432,076 36,664 - (3,900) 464,840
(FN)
(F1) Electric plant is being depreciated on the straight-line method at
rates designed to fully depreciate all depreciable properties by 2012.
(See Note 1 to the financial statements).
(B) Represents net salvage and removal costs.
(C) Represents disposal costs of spent nuclear fuel.
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our report dated February 7, 1994 included or
incorporated by reference in this Form 10-K, into Central Vermont Public
Service Corporation's previously filed Registration Statements on Form
S-8, File No. 33-22741, Form S-8, File No. 33-22742, Form S-8, File No.
33-58102, Form S-8, File No. 33-6200 and Form S-3, File No. 33-37095.
ARTHUR ANDERSEN & CO.
Boston, Massachusetts
March 25, 1994
CONSENT OF INDEPENDENT AUDITORS
The Board of Directors
Central Vermont Public Service Corporation:
We consent to the incorporation by reference in the Registration Statement
on Form S-8, File No. 33-22741, Form S-8, File No. 33-22742, Form S-8,
File No. 33-58102, Form S-8, File No. 33-6200, and Form S-3, File
No. 33-37095, of our report dated February 5, 1993 relating to the balance
sheet of Vermont Yankee Nuclear Power Corporation as of December 31, 1992
and the related statements of income and retained earnings and cash flows
for each of the years in the two-year period ended December 31, 1992,
which report is included in the December 31, 1993 Annual Report on Form
10-K of Central Vermont Public Service Corporation.
KPMG PEAT MARWICK
Boston, Massachusetts
March 24, 1994
EXHIBIT INDEX
Each document described below is incorporated by reference to the
files of the Securities and Exchange Commission, unless the reference to
the document is marked as follows:
* - Document has heretofore been filed with the Commission as is
incorporated by reference and made a part hereof.
Exhibit
Number Description
3. Articles of Incorporation and By-Laws
3-1 By-Laws, as amended December 3, 1990.
(Exhibit No. 3-1, 1990 10-K)
3-2 Articles of Association, as amended August 11, 1992.
(Exhibit No. 3-2, 1992 10-K)
4. Instruments defining the rights of security holders including
Indentures
Incorporated herein by reference:
B-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)
B-2 Supplemental Indenture dated as of August 1, 1936,
supplemental to B-1. (Exhibit B-4 File No. 2364)
B-3 Copy of Supplemental Indenture dated as of November 15, 1943,
supplemental to B-1. (Exhibit B-3, File No. 2-5250
B-4 Copy of Supplemental Indenture dated as of December 1,
1943, supplemental to B-1. (Exhibit No. B-4, File No.
2-5250)
B-5 Copy of directors' resolutions adopted December 14, 1943,
establishing the Series C Bonds and dealing with other
related matters, supplemental to B-1. (Exhibit B-5, File
No. 2-5250)
B-6 Copy of Supplemental Indenture dated as of April 1, 1944
supplemental to B-1. (Exhibit No. B-6, File No. 2-5466)
B-7 Copy of Supplemental Indenture dated as of February 1,
1945, supplemental to B-1. (Exhibit 7.6, File No. 2-5615
(22-385)
B-8 Directors' resolutions adopted April 9, 1945, establishing
the Series D Bonds and dealing with other matters, supplemental
to B-1. (Exhibit 7.8, File No. 2-5615 (22-385)
B-9 Copy of Supplemental Indenture dated as of September 2, 1947,
supplemental to B-1. (Exhibit 7.9, File No. 2-7489)
B-10 Copy of Supplemental Indenture dated as of July 15, 1948, and
directors' resolutions establishing the Series E Bonds and
dealing with other matters, supplemental to B-1. (Exhibit
7.10, File No. 2-8388)
B-11 Copy of Supplemental Indenture dated as of May 1, 1950, and
directors' resolutions establishing the Series F Bonds and
dealing with other matters, supplemental to B-1. (Exhibit 7.11,
File No. 2-8388)
B-12 Copy of Supplemental Indenture dated August 1, 1951, and and
directors'resolutions, establishing the Series G Bonds and
dealing with other matters, supplemental to B-1. (Exhibit 7.12,
File No. 2-9073)
B-13 Copy of Supplemental Indenture dated May 1, 1952, and
directors' resolutions, establishing the Series H Bonds and
dealing with other matters, supplemental to B-1. (Exhibit
4.3.13, File No. 2-9613)
B-14 Copy of Supplemental Indenture dated as of July 10, 1953,
supplemental to B-1. (July, 1953 Form 8-K)
B-15 Copy of Supplemental Indenture dated as of June 1, 1954, and
directors' resolutions establishing the Series K Bonds and
dealing with other matters, supplemental to B-1. (Exhibit
4.2.16, File No. 2-10959)
B-16 Copy of Supplemental Indenture dated as of February 1, 1957
and directors' resolutions establishing the Series L Bonds and
dealing with other matters, supplemental to B-1. (Exhibit
4.2.16, File No. 2-13321)
B-17 Copy of Supplemental Indenture dated as of March 15, 1960,
supplemental to B-1. (March, 1960 Form 8-K)
B-18 Copy of Supplemental Indenture dated as of March 1, 1962,
supplemental to B-1. (March, 1962 Form 8-K)
B-19 Copy of Supplemental Indenture dated as of March 2, 1964,
supplemental to B-1. (March, 1964 Form 8-K)
B-20 Copy of Supplemental Indenture dated as of March 1, 1965, and
directors' resolutions establishing the Series M Bonds and
dealing with other matters, supplemental to B-1. (April, 1965
Form 8-K)
B-21 Copy of Supplemental Indenture dated as of December 1, 1966,
and directors' resolutions establishing the Series N Bonds
and dealing with other matters, supplemental to B-1.
(January, 1967 Form 8-K)
B-22 Copy of Supplemental Indenture dated as of December 1, 1967,
and directors' resolutions establishing the Series O Bonds and
dealing with other matters, supplemental to B-1. (December,
1967 Form 8-K)
B-23 Copy of Supplemental Indenture dated as of July 1, 1969, and
directors' resolutions establishing the Series P Bonds and
dealing with other matters, supplemental to B-1. (July, 1969
Form 8-K)
B-24 Copy of Supplemental Indenture dated as of December 1, 1969, and
directors' resolutions establishing the Series Q Bonds January,
and dealing with other matters, supplemental to B-1. (January,
1970 Form 8-K)
B-25 Copy of Supplemental Indenture dated as of May 15, 1971, and
directors' resolutions establishing the Series R Bonds and
dealing with other matters, supplemental to B-1. (May, 1971
Form 8-K)
B-26 Copy of Supplemental Indenture dated as of April 15, 1973, and
directors' resolutions establishing the Series S Bonds and
dealing with other matters, supplemental to B-1. (May, 1973
Form 8-K)
B-27 Copy of Supplemental Indenture dated as of April 1, 1975, and
directors' resolutions establishing the Series T Bonds and
dealing with other matters, supplemental to B-1. (April, 1975
Form 8-K)
B-28 Copy of Supplemental Indenture dated as of April 1, 1977,
modifying B-1. (Exhibit 2.42, File No. 2-58621)
B-29 Copy of 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, supplemental to B-1.
(Exhibit 2.43, File No. 2-58621)
B-30 Copy of Thirtieth Supplemental Indenture dated as of
September 15, 1978, and directors' resolutions establishing
the Series Y Bonds and dealing with other matters,
supplemental to B-1. (Exhibit B-30, 1980 Form 10-K)
B-31 Copy of Thirty-first Supplemental Indenture dated as of
September 1, 1979, and directors' resolutions establishing
the Series Z Bonds and dealing with other matters,
supplemental to B-1. (Exhibit B-31, 1980 Form 10-K)
B-32 Copy of Thirty-second Supplemental Indenture dated as of June 1,
1981, and directors' resolutions establishing the Series AA
Bonds and dealing with other matters, supplemental to B-1.
(Exhibit B-32, 1981 Form 10-K)
B-33 Copy of Trust Indenture dated as of May 1, 1962, between the
Company and Mellon National Bank and Trust Company, Trustee,
relating to the Company's 4 7/8% Debentures due May 1, 1987.
(Exhibit 4.2.24, File No. 2-26485)
B-34 Copy of Trust Indenture dated as of May 1, 1968, between the
Company and The First National Bank of Boston, Trustee,
relating to the Company's 7% Debentures due May 1, 1993.
(May, 1986 Form 8-K)
B-35 Copy of Trust Indenture dated as of April 1, 1970, between the
Company and The First National Bank of Boston, Trustee, relating
to the Company's 10 5/8% Debentures due April 1, 1995.
(April, 1970 Form 8-K)
B-36 Copy of Indenture of Mortgage, dated as of September 1, 1957,
between Vermont Electric Power Company, Inc. ("Velco") and
Bankers Trust Company, securing Velco's First Mortgage Bonds.
(Exhibit (b)(1), 1957 Form 10-K)
B-37 Copy of Supplemental Indenture dated as of December 1, 1958,
modifying B-36. (Exhibit (b)(1), 1958 Form 10-K)
B-38 Copy of Supplemental Indenture dated as of December 1, 1969,
modifying B-36. (Exhibit 2.35, File 2-57458)
B-39 Copy of Supplemental Indenture dated as of November 1, 1970,
modifying B-36. (Exhibit 2.36, File No. 2-57458)
B-40 Copy of Supplemental Indenture dated as of December 1, 1971,
modifying B-36. (Exhibit 2.37, File No. 2-57458)
B-41 Copy of Supplemental Indenture dated as of December 1, 1972,
modifying B-36. (Exhibit 2.38, File No. 2-57458)
B-42 Copy of Supplemental Indenture dated as of July 1, l974,
modifying B-36. (Exhibit 2.39, File No. 2-57458)
B-43 Copy of Supplemental Indenture dated as of January 1, 1975,
modifying B-36. (Exhibit 2.40, File No. 2-57458)
B-44 Copy of Supplemental Indenture dated as of January 1, 1979,
modifying B-36. (Exhibit B-44, 1981 Form 10-K)
B-45 Copy of Thirty-third Supplemental Indenture dated as of
August 15, 1983, and directors' resolutions establishing the
Series BB Bonds and dealing with other matters, supplemental
to B-1. (Exhibit B-45, 1983 Form 10-K)
B-46 Copy of 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)
B-47 Copy of 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, supplemental to B-1. (B-47, 1985 Form 10-K)
B-48 Copy of 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)
B-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)
4-50 Copy of 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, supplemental to B-1. (Exhibit 4-50,
1989 Form 10-K)
4-51 Copy of Thirty-Sixth Supplemental Indenture dated as of
December 10, 1990 and directors' resolutions establishing the
Series HH Bonds and matters connected therewith, supplemental
to B-1. (Exhibit 4-51, 1990 Form 10-K)
4-52 Copy of Thirty-Seventh Supplemental Indenture dated December 10,
1991 and directors' resolutions establishing the Series JJ Bonds
and matters connected therewith, supplemental to B-1.
(Exhibit 4-52, 1991 Form 10-K)
* 4-53 Copy of Thirty-Eight Supplemental Indenture dated December 10,
1993 establishing Series KK, LL, MM, NN, OO supplemental to B-1
(Exhibit 4-53, 1993 Form 10-K)
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 C-2, 1957 Form 10-K)
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)
10.2.4 Amendment dated September 24, 1980. (Exhibit C-93, 1982
Form 10-K)
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 C-5, 1957 Form 10-K)
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 C-91, 1982
Form 10-K)
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)
10.4.2 Agreement Amending Superseding Three Party Power
Agreement dated May 1, 1991. (Exhibit 10.4.2, 1991 Form
10-K)
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
C-51, 1980 Form 10-K)
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)
10.8 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. (C-106, 1983 Form
10-K)
10.8.2 Copy of Additional Power Contract dated February 1,
1984. (Exhibit C-123, 1984 Form 10-K )
10.8.3 Amendment No. 3 to Vermont Yankee Power Contract,
dated April 24, 1985. (Exhibit 10-144, 1986 Form 10-K)
10.8.4 Amendment No. 4 to Vermont Yankee Power Contract,
dated June 1, 1985. (Exhibit 10-145, 1986 Form 10-K)
10.8.5 Amendment No. 5 dated May 6, 1988. (Exhibit 10-179,
1988 Form 10-K)
10.8.6 Amendment No. 6 dated May 6, 1988. (Exhibit 10-180,
1988 Form 10-K)
10.8.7 Amendment No. 7 dated June 15, 1989. (Exhibit 10-195,
1989 Form 10-K)
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 )
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)
10.10.2 Amendment No. 2 effective January 1, 1984. (Exhibit
C-113, 1984 Form 10-K)
10.10.3 Amendment No. 3 dated October 1, 1984. (Exhibit
C-114, 1984 Form 10-K)
10.10.4 Additional Power Contract dated February 1, 1984.
(Exhibit C-126, 1985 Form 10-K)
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 C-59, 1981
Form 10-K)
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 C-60, 1981
Form 10-K)
10.15 Copy of Stockholders Agreement dated March 29, 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 C-52,
1980 Form 10-K)
10.16.2 Amendment dated January 23, 1977. (Exhibit C-53
1980 Form 10-K)
10.16.3 Amendment dated July 1, 1977. (Exhibit C-54, 1980
Form 10-K)
10.16.4 Amendment dated August 1, 1977. (Exhibit C-55,
1980 Form 10-K)
10.16.5 Amendment dated August 15, 1978. (Exhibit C-56,
1980 Form 10-K)
10.16.6 Amendment dated January 31, 1979. (Exhibit C-57
1980 Form 10-K)
10.16.7 Amendment dated Feburary 1, 1980. (Exhibit C-58,
1980 Form 10-K)
10.16.8 Amendment dated December 31, 1976. (Exhibit C-72,
1981 Form 10-K)
10.16.9 Amendment dated January 31, 1977. (Exhibit C-73,
1981 Form 10-K)
10.16.10 Amendment dated July 1, 1977. (Exhibit C-74,
1981 Form 10-K)
10.16.11 Amendment dated August 1, 1977. (Exhibit C-75,
1981 Form 10-K)
10.16.12 Amendment dated August 15, 1978. (Exhibit C-76,
1981 Form 10-K)
10.16.13 Amendment dated January 31, 1980. (Exhibit C-77,
1981 Form 10-K)
10.16.14 Amendment dated February 1, 1980. (Exhibit C-78,
1981 Form 10-K)
10.16.15 Amendment dated September 1, 1981. (Exhibit C-79
1981 Form 10-K)
10.16.16 Amendment dated December 1, 1981. (Exhibit C-80
1981 Form 10-K)
10.16.17 Amendment dated June 15, 1983. (Exhibit C-105,
1983 Form 10-K)
10.16.18 Amendment dated September 1, 1985. (Exhibit
10-160, 1986 Form 10-K)
10.16.19 Amendment dated April 30, 1987. (Exhibit 10-172, 1987
Form 10-K)
10.16.20 Amendment dated March 1, 1988. (Exhibit 10-178, 1988
Form 10-K)
10.16.21 Amendment dated March 15, 1989. (Exhibit 10-194, 1989
Form 10-K)
10.16.22 Amendment dated October 1, 1990. (Exhibit 10-203,
1990 Form 10-K)
10.16.23 Amendment dated September 15, 1992. (Exhibit
10.16.23, 1992 Form 10-K)
10.16.24 Amendment dated May 1, 1993
10.16.25 Amendment dated June 1, 1993
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 Amendent 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.
(Ehibit C-32, File No. 2-55450)
10.17.10 Amendment 23 dated as of 1975. (Exhibit C-50, 1975
Form 10-K)
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, l974, 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. (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)
10.19.14 Fifteenth Amendment dated April 27, 1984. (Exhibit
10-134, 1986 Form 10-K)
10.19.15 Sixteenth Amendment dated June 15, 1984. (Exhibit
10-135, 1986 Form 10-K)
10.19.16 Seventeenth Amendment dated March 8, 1985. (Exhibit
10-136, 1986 Form 10-K)
10.19.17 Eighteenth Amendment dated March 14, 1986. (Exhibit
10-137, 1986 Form 10-K)
10.19.18 Nineteenth Amendment dated May 1, 1986. (Exhibit
10-138, 1986 Form 10-K)
10.19.19 Twentieth Amendment dated September 19, 1986.
(Exhibit 10-139, 1986 Form 10-K)
10.19.20 Amendment No. 22 dated January 13, 1989. (Exhibit
10-193, 1989 Form 10-K)
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. 248966)
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)
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)
10.25.1 Revision dated April 1, 1975. (Exhibit C-61, 1981
Form 10-K)
10.25.2 Amendment dated May 6, 1988. (Exhibit 10-181, 1988
Form 10-K)
10.25.3 Amendment dated June 26, 1989. (Exhibit 10-196, 1989
Form 10-K)
10.25.4 Amendment dated July 1, 1989. (Exhibit 10-197, 1989
Form 10-K)
10.25.5 Amendment dated February 1, 1992 (Exhibit 10.25.5,
1992 Form 10-K)
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)
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)
10.27.1 Supplementary Power Contract dated March 1, 1978.
(Exhibit C-94, 1982 Form 10-K)
10.27.2 Amendment dated August 22, 1980. (Exhibit C-95
1982 Form 10-K)
10.27.3 Amendment dated October 15, 1982. (Exhibit C-96,
1982 Form 10-K)
10.27.4 Second Supplementary Power Contract dated April 30,
1984. (Exhibit C-115, 1984 Form 10-K)
10.27.5 Additional Power Contract dated April 30, 1984.
(Exhibit C-116, 1984 Form 10-K)
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)
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)
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)
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)
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)
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)
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)
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)
10.34.1 Amendment dated June 1, 1982. (Exhibit C-98, 1982
Form 10-K)
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)
10.35.1 Amendment No. 1 dated January 1, 1986. (Exhibit
C-132, 1986 Form 10-K)
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)
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)
10.37.1 Amendment No. 3 dated January 1, 1986. (Exhibit
10-149, 1986 Form 10-K)
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)
10.39 Power Purchase Agreement between Velco and CVPS dated June 1,
1981. (Exhibit C-103, 1982 Form 10-K)
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
10.40.1 Amendment No. 1 dated October 5, 1982. (Exhibit
C-108, 1983 Form 10-K)
10.40.2 Amendment No. 2 dated December 30, 1983. (Exhibit
C-109, 1983 Form 10-K)
10.40.3 Amendment No. 3 dated January 10, 1984. (Exhibit
10-143, 1986 Form 10-K)
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)
10.42 Copy of Highgate Transmission Interconnection Preliminary
Support Agreement dated April 9, 1984. (Exhibit C-117, 1984
Form 10-K)
10.43 Copy of Allocation Contract for Hydro-Quebec Firm Power dated
July 25, 1984. (Exhibit C-118, 1984 Form 10-K)
10.43.1 Tertiary Energy for Testing of the Highgate HVDC
Station Agreement, dated September 20, 1985. (Exhibit
C-129, 1985 Form 10-K)
10.44 Copy of Highgate Operating and Management Agreement dated
August 1, 1984. (Exhibit C-119, 1986 Form 10-K)
10.44.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-152,
1986 Form 10-K)
10.44.2 Amendment No. 2 dated November 13, 1986. (Exhibit
10-167, 1987 Form 10-K)
10.44.3 Amendment No. 3 dated January 1, 1987. (Exhibit
10-168, 1987 Form 10-K)
10.45 Copy of Highgate Construction Agreement dated August 1, 1984.
(Exhibit C-120, 1984 Form 10-K)
10.45.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-151,
1986 Form 10-K)
10.46 Copy of Agreement for Joint Ownership, Construction and
Operation of the Highgate Transmission Interconnection.
(Exhibit C-121, 1984 Form 10-K)
10.46.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-153,
1986 Form 10-K)
10.46.2 Amendment No. 2 dated April 18, 1985. (Exhibit
10-154, 1986 Form 10-K)
10.46.3 Amendment No. 3 dated February 12, 1986. (Exhibit
10-155, 1986 Form 10-K)
10.46.4 Amendment No. 4 dated November 13, 1986. (Exhibit
10-169, 1987 Form 10-K)
10.46.5 Amendment No. 5 and Restatement of Agreement dated
January 1, 1987. (Exhibit 10-170, 1987 Form 10-K)
10.47 Copy of the Highgate Transmission Agreement dated August 1,
1984. (Exhibit C-122, 1984 Form 10-K)
10.48 Copy of Preliminary Vermont Support Agreement Re: Quebec
Interconnection - Phase II dated September 1, 1984. (Exhibit
C-124, 1984 Form 10-K)
10.48.1 First Amendment dated March 1, 1985. (Exhibit C-127,
1985 Form 10-K)
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)
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)
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)
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)
10.52 Agreement of Purchase & Sale of 1.59096% Seabrook Ownership
between Central Vermont Public Service Corporation and Eastern
Utilities Associates dated February 19, 1986. (Exhibit 10-140,
1986 Form 10-K)
10.52.1 Addendum dated June 27, 1986. (Exhibit 10-141, 1986
Form 10-K)
10.53 Agreement between Bangor Hydro-Electric Company, Central Maine
Power Company, Central Vermont Public Service Corporation,
Fitchburg Gas and Electric Light Company, Maine Public Service
Company and EUA Power Corporation dated October 20, 1986
conveying interests in transmission project facilities related
to Seabrook. (Exhibit 10-142, 1986 Form 10-K)
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)
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 10-146, 1986 Form 10-K)
10.55.1 Amendment dated February 1, 1987. (Exhibit 10-171,
1987 Form 10-K)
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)
10.56.1 Amendment No. 1 dated September 28, 1988. (Exhibit
10-182, 1988 Form 10-K)
10.56.2 Amendment No. 2 dated October 1, 1991. (Exhibit
10.56.2, 1991 Form 10-K)
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)
10.57.1 Amendment No. 1 dated September 22, 1985. (Exhibit
10-157, 1986 Form 10-K)
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)
10.58.1 Amendment No. 1 dated June 20, 1986. (Exhibit 10-159,
1986 Form 10-K)
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)
10.59.1 Amendment No. 17 dated November 25, 1985. (Exhibit
10-162, 1986 Form 10-K)
10.60 Memorandum of Understanding by and between The Champlain
Pipeline Company and Northern New England Gas Corporation,
Noverco Corporation and Central Vermont Equity Corporation
dated February 2, 1987. (Exhibit 10-163, 1987 Form 10-K)
10.60.1 Amendment No. 1 dated April 10, 1987. (Exhibit
10-164, 1987 Form 10-K)
10.60.2 Assignment Agreement by and between CV Energy
Resources, Inc. and CV Champlain Investments, Inc.
dated December 31, 1987. (Exhibit 10-165, 1987)
10.61 General Partnership Agreement re: Champlain Pipeline
Partnership dated January 1, 1988 by and between Noverco,
Northern New England Gas Corporation, CV Energy Resources, Inc.
and Providence Energy Corporation. (Exhibit 10-166, 1987 Form
10-K)
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)
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)
* 10.63.1 Amendment dated September 1, 1993 (Exhibit 10.63.1,
1993 Form 10-K)
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)
10.64.1 Amendment No. 1 dated August 31, 1988. (Exhibit
10-191, 1988 Form 10-K)
10.64.2 Amendment No. 2 dated September 19, 1990. (Exhibit
10-202, 1990 Form 10-K)
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)
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)
10.65 Settlement Agreement between EUA Power Corporation, Bangor
Hydro-Electric Company, Central Maine Power Company, Central
Vermont Public Service Corporation and Maine Public Service
Company dated January 31, 1988 re: Seabrook real estate.
(Exhibit 10-176, 1988 Form 10-K)
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)
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)
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
10.68 Stock Option Plan for Non-Employee Directors dated July 18,
1988. (Exhibit 10-184, 1988 Form 10-K)
10.69 Stock Option Plan for Key Employees dated July 18, 1988.
(Exhibit 10-185, 1988 Form 10-K)
10.70 Officers Supplemental Insurance Plan authorized July 9, 1984.
(Exhibit 10-186, 1988 Form 10-K)
10.71 Officers Supplemental Deferred Compensation Plan dated November
4, 1985. (Exhibit 10-187, 1988 Form 10-K)
10.72 Directors' Supplemental Deferred Compensation Plan dated
November 4, 1985. (Exhibit 10-188, 1988 Form 10-K)
10.73 Management Incentive Compensation Plan as adopted September 9,
1985. (Exhibit 10-189, 1988 Form 10-K)
10.73.1 Revised Management Incentive Plan as adopted February
5, 1990. (Exhibit 10-200. 1989 Form 10-K)
10.74 Officers' Change of Control Agreements as approved October 3,
1988. (Exhibit 10-190, 1988 Form 10-K)
* 10.78 Stock Option Plan for Non-Employee Directors dated April 30,
1993 (Exhibit 10.78, 1993 Form 10-K)
* 10.79 Officers Insurance Plan dated November 15, 1993
(Exhibit 10.79, 1993 Form 10-K)
* 10.80 Directors'Supplemental Deferred Compensation Plan dated
(Exhibit 10.80, 1993 Form 10-K)
* 10.81 Officers' Supplemental Deferred Compensation Plan dated
(Exhibit 10.81, 1993 Form 10-K)
--------------------------------------------
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)
* 10.75.2 Letter Agreement dated December 4, 1989
(Exhibit 10.75.2, 1993 Form 10-K)
* 10.75.3 Agreement Amendment No. 2 dated November 29, 1990
(Exhibit 10.75.3, 1993 Form 10-K)
* 10.75.4 Agreement Amendment No. 3 dated November 29, 1991
(Exhibit 10.75.4, 1993 Form 10-K)
* 10.75.5 Agreement Amendment No. 4 dated November 29, 1992
(Exhibit 10.75.5, 1993 Form 10-K)
10.76 Power Purchase Agreement with Bonneville Pacific Corporation,
Unit I, dated November 15, 1989. (Exhibit 10-198, 1989 Form
10-K)
10.77 Power Purchase Agreement with Bonneville Pacific Corporation,
Unit II, dated November 15, 1989. (Exhibit 10-199, 1989 Form
10-K)
* 10.82 Transmission Service Agreement between this Company and Green
Mountain Power Corporation dated September 1, 1993
(Exhibit 10.82, 1993 Form 10-K)
11. Not applicable.
12. Not applicable.
13. 1992 Annual Report to Stockholders
* 13.1 Portions of the Annual Report to Stockholders of Central Vermont
Public Service Corporation that have been incorporated by
reference under Items 6, 7 and 8
16. Change in certifying accountant (July 1, 1985 Form 8-K)
18. Letter re change in accounting principles (1980 3rd Quarter Form 10-Q)
21. Subsidiaries of the Registrant
* 21.1 List of subsidiaries of registrant
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/ Thomas C. Webb
Thomas C. Webb, President and
Chief Executive Officer
By /s/ Robert H. Young
Robert H. Young, Executive Vice President -
Chief Operating Officer
and Principal Financial Officer
By /s/ James M. Pennington
James M. Pennington, Controller
and Principal Accounting Officer
March 14, 1994
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.
March 14, 1994 /s/ Frederic H. Bertrand
Frederic H. Bertrand
Director
March 14, 1994 /s/ Robert P. Bliss, Jr.
Robert P. Bliss, Jr.
Director
March 14, 1994 /s/ Elizabeth Coleman
Elizabeth Coleman
Director
March 14, 1994 /s/ Luther F. Hackett
Luther F. Hackett
Director
March 14, 1994 /s/ F. Ray Keyser, Jr.
F. Ray Keyser, Jr.
Director
March 14, 1994 /s/ Mary Alice McKenzie
Mary Alice McKenzie
Director
March 14, 1994 /s/ Gordon P. Mills
Gordon P. Mills
Director
March 14, 1994 /s/ Preston Leete Smith
Preston Leete Smith
Director
March 14, 1994 /s/ Robert D. Stout
Robert D. Stout
Director
March 14, 1994 /s/ Thomas C. Webb
Thomas C. Webb
Director
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
Annual Report Pursuant to Section 13 of 15(d) of the
Securities Exchange Act of 1934
For the fiscal year ended Commission File No. 1-8222
December 31, 1993
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
EXHIBITS
TO
1993 FORM 10-K
INDEX
List of Exhibits
1993 Form 10-K
4-53 Copy of Thirty-Eight Supplemental Indenture dated December 10,
1993 establishing Series KK, LL, MM, NN, OO supplemental to
B-1
10.16.24 Amendment dated May 1, 1993.
10.16.25 Amendment dated June 1, 1993
10.63.1 Amendment dated September 1, 1993
10.75.1 Agreement Amendment No. 1 dated December 21, 1988
10.75.2 Letter Agreement dated December 4, 1989
10.75.3 Agreement Amendment No. 2 dated November 29, 1990
10.75.4 Agreement Amendment No. 3 dated November 29, 1991
10.75.5 Agreement Amendment No. 4 dated November 29, 1992
10.78 Stock Option Plan for Non-Employee Directors dated April 30,
1993
10.79 Officers Insurance Plan dated November 15, 1993
10.80 Directors'Supplemental Deferred Compensation Plan dated
January 1, 1990
10.81 Officers' Supplemental Deferred Compensation Plan dated
January 1, 1990
10.82 Transmission Service Agreement between this Company and Green
Mountain Power Corporation dated September 1, 1993
13 Annual Report to Security holders
13.1 Portions of the Annual Report to Stockholders of
Central Vermont Public Service Corporation that have been
incorporated by reference under Items 6, 7 and 8
18. Letter re change in accounting principles (1980 3rd Quarter Form 10-Q)
21. Subsidiaries of the Registrant
* 21.1 List of subsidiaries of registrant