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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, 1994
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. [X]
Cover page
State the aggregate market value of the voting stock held by non-
affiliates of the registrant: $158,100,498 based upon the closing price as of
January 31, 1995 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, 1995, there were outstanding
11,711,148 shares of Common Stock, $6 Par Value.
DOCUMENTS INCORPORATED BY REFERENCE
No documents are incorporated by reference in this report.
Cover page continued
Form 10-K - 1994
TABLE OF CONTENTS
Page
Part I
Item 1. Business................................................ 2
Item 2. Properties.............................................. 16
Item 3. Legal Proceedings....................................... 17
Item 4. Submission of Matters to a Vote of Security Holders..... 17
Part II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters.................................... 18
Item 6. Selected Financial Data................................. 19
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 20
Item 8. Financial Statements and Supplementary Data............. 29
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.................... 53
Part III
Item 10. Directors and Executive Officers of the Registrant...... 53
Item 11. Executive Compensation.................................. 56
Item 12. Security Ownership of Certain Beneficial Owners and
Management............................................. 62
Item 13. Certain Relationships and Related Transactions.......... 63
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K............................................ 64
Signatures........................................................ 83
PART I
Item 1. Business.
Overview.
Central Vermont Public Service Corporation (the "Company"), incorporated
under the laws of Vermont on August 20, 1929, is engaged in the purchase,
production, transmission, distribution and sale of electricity. The Company
has various wholly and partially owned subsidiaries. These subsidiaries are
described below.
The Company is the largest electric utility in Vermont and serves 135,704
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 municipal, one rural cooperative, and one private utility.
The Company's sales are derived from a diversified customer mix. The
Company's sales to residential, commercial and industrial customers accounted
for 56% of total MWH sales for the year 1994. Sales to the five largest
retail customers receiving electric service from the Company during the same
period constituted about 4.7% of the Company's total electric revenues for the
year. The Company's requirements resale sales accounted for approximately 4%,
entitlement sales accounted for 23% and other resale sales which include
contract sales, opportunity sales and sales to NEPOOL accounted for
approximately 17% of total MWH sales for the year 1994.
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 10,261 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 1994. Sales to its five largest retail customers during the same
period equaled about 17.9% 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 primary purpose is to invest in non-regulated, energy-supply
projects, CV Energy Resources, Inc. whose primary purpose is to invest in non-
regulated energy-related projects 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 currently has four wholly owned
subsidiaries: (See "DIVERSIFICATION"); Catamount Rumford Corp., Equinox
Vermont Corporation, Appomattox Vermont Corp. and Catamount Williams Lake L.P.
For additional information of the Company's diversification activities, see
Item 8 herein.
REGULATION AND COMPETITION
State Commissions.
The Company is subject to the regulatory authority of the Vermont Public
Service Board ("PSB") with respect to rates, and the Company and VELCO are
subject to PSB jurisdiction respecting securities issues, construction of
major generation and transmission facilities and various other matters. The
Company is subject to the regulatory authority of the New Hampshire Public
Utilities Commission as to matters pertaining to construction and transfers of
utility property in New Hampshire. Additionally, the Public Utilities
Commission of Maine and the Connecticut Department of Public Utility Control
exercise limited jurisdiction over the Company based on its 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.
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. For
additional information see Item 7 herein and refer to Item 8 herein for
disclosures relating to environmental contingencies, hazardous substance
releases and the control measures related thereto.
Nuclear Matters.
The nuclear generating facilities of Vermont Yankee and the other nuclear
facilities in which the Company has an interest are subject to extensive
regulations by the Nuclear Regulatory Commission ("NRC"). The NRC is
empowered to regulate the siting, construction and operation of nuclear
reactors with respect to public health, safety, environmental and antitrust
matters. Under its continuing jurisdiction, the NRC may, after appropriate
proceedings, require modification of units for which operating licenses have
already been issued, or impose new conditions on such licenses, and may
require that the operation of a unit cease or that the level of operation of
a unit be temporarily or permanently reduced. Refer to Item 8 herein for
disclosures relating to the shut down of the Yankee Atomic Nuclear Power
plant.
Competition.
Competition now takes several forms. At the wholesale level, where the
utility-to-utility market has been highly competitive for years, independent
companies now compete to be the low-cost providers of power to local and
regional utilities. A growing competitive threat is rooted in the belief that
lower priced electricity could be made available to residents and business by
voters establishing a municipally owned utility. At the retail level,
customers have long had energy options such as propane, natural gas or oil for
heating, cooling and water heating, and self-generation for larger customers.
Changes anticipated as a result of the National Energy Policy Act of 1992 and
evolving state regulatory policy may even bring about direct utility-to-
utility competition for these retail customers.
However, pursuant to Vermont statutes (30 V.S.A. Section 249), the PSB
has established as the service area for the Company the area it now serves.
Under 30 V.S.A. Section 251(b) no other company is legally entitled to serve
any retail customers in the Company's established service area.
An amendment to 30 V.S.A. Section 212(a) enacted May 28, 1987 authorizes
the Vermont Department of Public Service ("Department") to purchase and
distribute power at retail to all customers of electricity in Vermont, subject
to certain preconditions specified in new sections 212(b) and 212(c). Section
212(b) provides that a review board consisting of the Governor and certain
other designated legislative officers review and approve any retail proposal
by the Department if they are satisfied that the benefits outweigh any
potential risk to the State. However, the Department may proceed to file the
retail proposal with the PSB either upon approval by the review board or the
failure of the board to act within sixty (60) days of the submission. Section
212(c) provides that the Department shall not enter into any retail sales
arrangement before the PSB determines and approves certain findings. Those
findings are (1) the need for the sale, (2) the rates are just and reasonable,
(3) the sale will result in economic benefit, (4) the sale will not adversely
affect system stability and reliability and (5) the sale will be in the best
interest of ratepayers.
Section 212(d) provides that upon PSB approval of the Department retail
sales proposal, Vermont utilities shall make arrangements for distributing
such electricity on terms and conditions that are negotiated. Failing such
negotiation, the PSB is directed to determine such terms as will compensate
the utility for all costs reasonably and necessarily incurred to provide such
arrangements. See Rate Developments below for additional details involving
retail sales by the Department.
In addition, Chapter 79 of Title 30 authorizes municipalities to acquire
the electric distribution facilities located within their boundaries. The
exercise of such authority is conditioned upon an affirmative three-fifths
vote of the legal voters in an election and upon the payment of just
compensation including severance damages. Just compensation is determined
either by negotiation between the municipality and the utility or, in the
event the parties fail to reach an agreement, by the Public Service Board
after a hearing. If either party is dissatisfied, the statute allows them to
appeal the Board's determination to the Vermont Supreme Court. Once the price
is determined, whether by agreement of the parties or by the PSB, a second
affirmative three-fifths vote of the legal voters is required.
Competition in the energy services market exists between electricity and
fossil fuels. In the residential and small commercial sectors this
competition is primarily for electric space and water heating from propane and
oil dealers. Competitive issues are price, service, convenience, cleanliness
and safety.
In the large commercial and industrial sectors, cogeneration and self-
generation are the major competitive threats to electric sales. Competitive
risks in these market segments are primarily related to seasonal, one-shift
operations that can tolerate periodic power outages, and for industrial
customers with steady heat loads where the generator's waste heat can be used
in their manufacturing process. Competitive advantages for electricity in
those segments are the cost of back up power sources, space requirements,
noise problems, and maintenance requirements.
There has been only one instance where Chapter 79 of Title 30 has been
invoked; the Town of Springfield acted to acquire the Company's distribution
facilities in that community pursuant to a vote in 1977. This action was
subsequently discontinued by agreement between Springfield and the Company in
1985.
In addition, in late 1994 the Select Board of the Town of Bennington
considered whether to publicly warn a vote to acquire the Company's facilities
located in Bennington pursuant to Chapter 79 of Title 30. By vote of the
Selectors taken on January 9, 1995, the Town decided not to pursue the vote
and to discontinue further study of the creation of a municipal utility at
this time.
No other municipality served by the Company, so far as is known to the
Company, has taken any formal steps in an attempt to establish a municipal
electric distribution system.
For a discussion relating to the Company's wholesale electric business
see "Wholesale Rates" below.
RATE DEVELOPMENTS
Vermont Retail Rates.
In response to a March 1993 PSB inquiry into the appropriateness of a
general review of the Company's retail rates, in April 1993 the DPS and the
Company entered into a Stipulation that was approved by the PSB in September
1993. In the Stipulation the Company agreed 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 PSB consolidated
its investigation and the Company's rate increase request. The PSB also
broadened its investigation to specifically include the Company's management
of its power contracts. During the hearings, the PSB approved a settlement of
power costs between the DPS and the Company. The PSB's approval of such
settlement specifically excluded the as yet unknown effects of the PSB's
investigation of the Company's management of its power contracts.
By PSB order dated October 31, 1994 and revised PSB order dated
December 14, 1994, the PSB ordered (1) no changes in rates pursuant to its
investigation and (2) a $10.192 million or 5.07% rate increase effective
November 1, 1994 pursuant to the Company's rate increase request. The 10.75%
rate of return on common equity allowed by the PSB was reduced by a .75%
penalty based on the PSB's conclusions that there had been "mismanagement of
power supply options" and because of "the Company's failed efforts to acquire
all cost-effective energy efficiency resources."
The Company anticipates filing for future rate increases when cost
containment efforts are insufficient to offset the increasing cost of
providing service, primarily purchased power.
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. On the basis of estimates of costs for 1995
and reconciliations from 1994, the combined PPCA and FAC will result in a
decrease in revenues of approximately $489,000 or 2.7% for 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.
In October 1994 Connecticut Valley filed its annual update of the 1995
C&LMPA rates. When the schedule for hearings pointed to an effective date of
April 1, 1995, Connecticut Valley petitioned to let revised C&LMPA rates
become effective January 1, 1995. Such C&LMPA rates would be lower than they
would be at the April 1 effective date. In addition, the January 1 effective
date would coincide with the effective date of the FAC and PPCA so that one
rate change would be experienced by the customers. Connecticut Valley also
felt that further changes to the C&LMPA rates might not be necessary effective
April 1, 1995 depending on the outcome of the hearings. The NHPUC allowed a
$48,000 or 0.3% increase in the C&LMPA rates effective January 1, 1995.
Connecticut Valley also purchases power from several small power
producers who own qualifying facilities as defined by the Public Utility
Regulatory Policies Act of 1978. In 1994, under long-term contracts with
these qualifying facilities, Connecticut Valley purchased 4.3 MW, of which
3.9 MW were purchased from a New Hampshire/Vermont solid waste plant owned by
Wheelabrator Claremont Company, L.P., (Wheelabrator). Connecticut Valley has
filed a complaint with the Federal Energy Regulatory Commission (FERC) stating
its concern that Wheelabrator has not been a qualifying facility since the
plant began operation. Potential outcomes of this complaint could result in a
refund, with interest, of past purchased power costs as well as lower future
costs. Any refunds and lower future costs are likely to be reflected in the
FAC. Pursuant to a Company request, the NHPUC issued an accounting order
allowing deferral of litigation costs related to this FERC complaint, with
recovery to be determined when the outcome of the FERC complaint is known and
petitioned for implementation.
Wholesale Rates.
The Company sells firm power to Connecticut Valley under a wholesale rate
schedule based on forecast data for each calendar year which is reconciled to
actual data annually. The Company filed with the FERC for a revenue increase
of $466,000 or 4.7% for 1995 power costs. The rate schedule provides for an
automatic update of annual rates, as well as the subsequent reconciliation to
actual data.
As ordered by the NHPUC in Connecticut Valley's 1994 C&LMPA docket, the
Company entered into negotiations with the NHPUC Staff to redesign the RS-2
wholesale rate under which Connecticut Valley purchases power from the
Company. The redesign features marginal cost based energy and capacity
charges for all energy and capacity purchases above or below a base level.
Such negotiations concluded at the end of 1994. A summary report was filed
with the NHPUC on February 13, 1995. The NHPUC has yet to issue an order
approving the summary report. Connecticut Valley's costs of wholesale power
will be lower than they otherwise would be only if Connecticut Valley's growth
rate exceeds that of the Company's Vermont retail operations.
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 has entered into
negotiations to provide transmission service and will submit a bid 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 2,410,703 MWH for the year ended December 31, 1994.
The maximum one-hour integrated demand during that period was 414.6 MW, which
occurred on January 17, 1994. The Company's and Connecticut Valley's total
production in 1994, including production related to all resale customers, was
3,926,382 MWH.
The following tabulation shows the sources of such energy and capacity
available to the Company and Connecticut Valley for the year ended
December 31, 1994 and at the time of the Company's own peak. For additional
information related to purchased power costs, refer to Item 7 herein.
Year Ended December 31, 1994
_________________________________________________
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....................... 42.3 193,002 4.9 17.7 4.3
Diesel and Gas Turbine..... 28.4 403 - - -
JOINTLY OWNED PLANTS:
Millstone #3................ 19.8 163,069 4.2 18.8 4.5
Wyman #4.................... 11.0 7,180 0.2 9.4 2.3
McNeil...................... 10.5 18,166 0.5 10.0 2.4
EQUITY OWNERSHIP IN PLANTS:
(Purchased)
Vermont Yankee.............. 156.5 1,315,598 33.5 105.3 25.4
Maine Yankee................ 15.7 118,929 3.0 15.0 3.6
Connecticut Yankee.......... 11.5 76,035 1.9 11.1 2.7
MAJOR LONG-TERM PURCHASES:
Hydro-Quebec................ 179.2 704,742 17.9 68.9 16.6
Merrimack #2................ 47.0 280,107 7.1 23.8 5.8
OTHER PURCHASES:
System and other purchases.. 28.3 333,654 8.5 18.0 4.3
Small Power Producers....... 34.4 190,613 4.9 16.6 4.0
Unit Purchases.............. 90.0 244,148 6.2 77.3 18.6
Entitlement Purchases....... 0.2 14,711 0.4 - -
Pumped Storage Hydro........ 4.2 2,932 0.1 - -
NEPEX......................... - 263,093 6.7 22.7 5.5
----- --------- ----- ----- -----
TOTAL.................... 679.0 3,926,382 100.0 414.6 100.0
===== ========= ===== ===== =====
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% 20 163,069 93% $59,392,685
Connecticut
Wyman #4 Yarmouth, Oil 1.78% 11 7,179 7% $ 1,743,332
Maine
Joseph C. McNeil Burlington, Various 20.00% 10.6 18,166 20% $ 9,888,996
Vermont
Highgate Trans- Highgate Springs, 46.08% N/A N/A N/A $ 9,377,519
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. Based on a 1992 study, total estimated
decommissioning obligation at December 31, 1994 was approximately $449 million
and the funded obligation was about $76 million. The Company's share for the
total obligation and funded obligation was approximately $7.8 million and $1.1
million, respectively.
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 4.5% of its
entitlement. The Company's current equity ownership and net entitlement
percentages are 31.3 and 30.5, respectively.
The Atomic Energy Commission, now the NRC, granted a full-term (40-year),
full power operating license for the Vermont Yankee plant, which was to expire
in December 2007. On December 17, 1990 the NRC issued an amendment of the
operating license extending its term to March 2012.
Vermont Yankee's net capability is 514 MW of which 156.7 MW (See Note 1)
is the Company's net entitlement. Vermont Yankee's plant performance for the
past five years is shown below:
Availability Capacity
Factor Factor
(See Note 2) (See Note 3)
1990......................... 84.4 80.3
1991......................... 93.6 91.2
1992......................... 87.5 82.7
1993......................... 78.3 74.9
1994......................... 98.2 95.8
As described in the overview section above, the Company is a stockholder,
together with other New England electric utilities, in the following three
nuclear generating companies: Maine Yankee Atomic Power Company, Connecticut
Yankee Atomic Power Company and Yankee Atomic Electric Company.
Net Company's
Company Capability Entitlement
Maine Yankee (See Note 4)..... 847 MW 2.0% - 16.9 MW
Connecticut Yankee............ 582 MW 2.0% - 11.6 MW
Yankee Atomic................. (See Note 5) (See Note 5)
The Company is obligated to pay its entitlement percentage of the
operating expenses of Vermont Yankee and the other Yankee companies, including
depreciation and a return on invested capital, whether or not the plant is
operating. The Company is obligated to contribute its entitlement percentage
of the capital requirements of Vermont Yankee and Maine Yankee and has a
similar, but more limited obligation to Connecticut Yankee. The Company's
entitlement percentages are identical to the ownership percentages except that
Vermont Yankee's entitlement percentage is 35%. For additional information
regarding Equity Ownership in Plants, refer to Item 8 herein.
_______________
Notes:
(1) Currently, the Company resells at cost, through VELCO, 23.2 MW of its
original entitlement to other Vermont utilities.
(2) "Availability Factor" means the hours that the plant is capable of
producing electricity divided by the total hours in the period.
(3) "Capacity Factor" means the total net electrical generation divided by
the product of the maximum design electrical rating capacity of 514
multiplied by the total hours in the period.
(4) Currently, the Company resells at cost 1.8 MW of its entitlement to
certain municipal utilities in Massachusetts.
(5) Yankee Atomic permanently ceased power operations of the Yankee Nuclear
Power Station. See Decommissioning Expense discussion below.
Decommissioning Expense.
Each of the Yankee companies and Millstone #3 has developed its own
estimate of the cost of decommissioning its nuclear generating unit. These
estimates vary depending upon the method of decommissioning, economic
assumptions, site and unit specific variables, and other factors. Each of the
Yankee Companies includes charges for decommissioning costs in the cost of
capacity, as approved by the FERC. Decommissioning costs for Millstone #3 are
included in depreciation expenses.
The Company's entitlement percentage of decommissioning costs for Vermont
Yankee, Connecticut Yankee, Maine Yankee, Yankee Atomic and Millstone #3 is as
follows (dollars in millions):
CVPS's
Total Share of
Date of Estimated CVPS's Funded
Study Obligation Obligation Obligation
Nuclear generating companies:
Vermont Yankee 1993 $312.7 $109.4 $40.3
Maine Yankee 1993 $316.6 $6.3 $2.2
Connecticut Yankee 1992 $294.2 $5.9 $3.0
Yankee Atomic 1994 $370 $13.0 $3.6
Millstone #3 1992 $449 $7.8 $1.1
On February 26, 1992, the Board of Directors of Yankee Atomic decided to
permanently discontinue operation of their plant, and, to decommission the
facility.
The Company relied on Yankee Atomic for less than 1.5% of its system
capacity. Presently, purchased power costs billed to the Company by Yankee
Atomic, which include a provision for ultimate decommissioning of the unit,
are being collected from the Company's customers via existing retail rate
tariffs.
On March 18, 1993, the FERC approved a settlement agreement regarding the
decommissioning plan, recovery of plant investment and all issues with respect
to prudency of the decision to discontinue operation which included
$247 million of decommissioning costs in 1992 dollars. Based on a new study
developed by Yankee Atomic, decommissioning costs are approximately
$370 million in 1994 dollars. The increase results primarily from delays in
finding a permanent repository for its spent nuclear fuel. The new study is
subject to FERC approval. Yankee Atomic is currently collecting from sponsors
decommissioning costs based on $247 million in 1992 dollars and anticipates to
begin collecting from sponsors based on $370 million in November 1995. The
Company's share of the increase in decommissioning costs is approximately
$4.3 million.
The Company's total current share of its cost with respect to Yankee
Atomic's decision to discontinue operation is approximately $12.4 million.
This amount is reflected in the accompanying balance sheet both as a
regulatory asset and deferred power contract obligation (current and non-
current).
The Company believes that its proportionate share of Yankee Atomic costs
will be recovered through the regulatory process and, therefore, the ultimate
resolution of the premature retirement of the 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 or license lives. See Item 8 herein.
In 1982 the State of Maine enacted legislation that requires the
development of a decommissioning trust fund for the Maine Yankee nuclear
plant. This statute also provides that, if the trust has insufficient funds
to decommission the plant, the licensee, Maine Yankee, is responsible for the
deficiency and, if the licensee is unable to provide the entire amount, the
owners of the licensee are jointly and severally responsible for the
remainder. The definition of owner under the statute includes the Company.
It is expected that any payments required by the Company under these
provisions would be recovered through rates.
Nuclear Fuel.
Vermont Yankee has approximately $133 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 1997.
Vermont Yankee has a contract with the United States Department of Energy
("DOE") for the permanent disposal of spent nuclear fuel. Under the terms of
this contract, in exchange for the one-time fee discussed below and a
quarterly fee of $.001 per KWH of electricity generated and sold, the DOE
agrees to provide disposal services when a facility for spent nuclear fuel and
other high-level radioactive waste is available, which is required by contract
to be prior to January 31, 1998.
The DOE contract obligates Vermont Yankee to pay a one-time fee of $39.3
million for disposal costs for all spent fuel discharged through April 7,
1983. Although such amount has been collected in rates from the Sponsors,
Vermont Yankee has elected to defer payment of the fee to the DOE as permitted
by the DOE contract. The fee must be paid no later than the first delivery of
spent nuclear fuel to the DOE. Interest accrues on the unpaid obligation
based on the thirteen-week Treasury Bill rate and is compounded quarterly.
Through 1994 Vermont Yankee accumulated approximately $54 million 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 a 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 $.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 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 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, 1994, 1993 and 1992 approximately $.0, $.9 and
$1.6 million in principal and interest respectively, is reflected in other
accounts receivable in the Vermont Yankee's Balance Sheet.
The average energy and capacity costs to the Company of energy generated
at the Vermont Yankee plant was 4.60, 3.69, 4.71, 5.34 and 3.77 cents per KWH
for the years 1990 through 1994, respectively.
The Company has been advised by the companies operating other nuclear
generating stations in which the Company has an interest that they have
contracted for certain segments of the nuclear fuel production cycle through
various dates. Contracts for the remainder of the fuel cycle will be required
but their availability, prices and terms cannot be predicted.
Nuclear Liability and Insurance.
The Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $8.9 billion. Beyond that a licensee
maintains an indemnity agreement with the Nuclear Regulatory Commission, but
subject to Congressional approval. The first $200 million of liability
coverage is the maximum provided by private insurance. The Secondary
Financial Protection Program is a retrospective insurance plan providing
additional coverage up to $8.7 billion per incident by assessing $79.3 million
against each of the 110 reactor units that are currently subject to the
Program in the United States, limited to a maximum assessment of $10 million
per incident per nuclear unit in any one year. The maximum assessment is to
be adjusted at least every five years to reflect inflationary changes. The
Company's interests in the nuclear power units are such that it could become
liable for an aggregate of approximately $4.4 million of such maximum
assessment per incident per year.
Major long-term purchases.
Canadian Purchases - Under various contracts, the Company purchases from
Hydro-Quebec capacity and associated energy. Under the terms of these
contracts, the Company is required to pay certain fixed capacity costs whether
or not energy purchases above a minimum level described in the contracts are
made. Such minimum energy purchases must be made whether or not other less
expensive energy sources might be available.
The Company will receive varying amounts of capacity and energy from two
Hydro-Quebec contracts during the period 1995-2016. The contract between a
group of Vermont utilities (Vermont Joint Owners) and Hydro-Quebec provides
power over the entire period while a contract between the state of Vermont and
Hydro-Quebec terminates on September 22, 1995. Additional contracts were
negotiated between the Company and Hydro-Quebec which in effect reduce the
amount of power the Company is required to purchase, as well as one signed in
1994 which reduces the cost to the Company.
The maximum net amount of capacity that the Company will purchase during
the term of the agreements is 142.7 MW. The total commitment in the next five
years to purchase power under these contracts is approximately $321 million,
less approximately $112 million of power sellbacks, yielding a net cost of
approximately $209 million.
Early in the Vermont Joint Owners contract, two sellback contracts were
negotiated which reduced the net purchase of Hydro-Quebec power as well as
delayed the purchase of about 24 MW of capacity and associated energy. In
1994, the Company negotiated a third sellback arrangement whereby the Company
receives an effective discount on up to 70 MW of capacity in the 1996 contract
year (declining to 30 MW in the 1999 contract year) in exchange for the right
of Hydro-Quebec to reduce capacity deliveries by up to 50 MW beginning as
early as 2004 until 2015, and the ability to reduce the amounts of energy
delivered from a 75% to a 50% load factor up to five years beginning in 2000.
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-4
Capacity in MW 69 25 31 21 92 24
Contract period 1985-1995 1991-1995 1991-2012 1992-2012 1995-2015 1996-2016
Minimum energy capacity factor 50.0% 50.0% 75.0% 75.0% 75.0% 75.0%
Minimum annual energy in MWH 220,752 79,844 201,863 138,141 606,069 155,801
Actual 1994 energy charges $6,750 $3,266 $4,848 $3,422 N/A N/A
Est.1st full yr. future energy charges $5,662 $2,635 $4,893 $3,349 $15,204 $4,140
Est. avg. % change from 1st yr. future (100.0)% (100.0)% 3.5% 3.5% 3.5% 3.5%
(1995-1996) (1995-1996) (1995-2012) (1995-2012) (1995-2015) (1996-2016)
Actual 1994 annual capacity charge $4,511 $2,448 $7,041 $5,065 N/A N/A
Est.1st full yr.future capacity charge $3,237 $1,744 $7,271 $5,041 $23,246 $6,189
Est. avg. % change from 1st yr. future (100.0)% (100.0)% - - - -
(1995-1996) (1995-1996) (1995-2012) (1995-2012) (1995-2015) (1996-2016)
Actual 1994 avg. cost in cents/KWH 2.8 5.2 5.9 6.0 N/A N/A
Est. 1st full yr. future avg. cost
in cents/KWH 2.7 5.5 6.0 6.1 6.3 6.6
Est. avg. % change from 1st yr future N/A N/A 1.4% 1.4% 1.4% 1.4%
(1995-1996) (1995-1996) (1995-2012) (1995-2012) (1995-2015) (1996-2016)
1994 Sell-back in MW 25 30 20
Actual 1994 sell-back revenues $5,714 $9,354 $6,664
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 $4,379 $1,650 $1,090
(1995) (1995) (1995)
Est. out-yrs. average annual N/A $11,420
Est. average annual % change (100.0)% 1.4%
(1996) (1996-2012)
Expected sell-back #2 revenues up to 30 MW 20 MW
Approx. 78% of costs on average
Estimated 1995 annual $7,740 $6,250
Estimated 1996 annual $1,470 $5,020
Expected sell-back #3 revenues up to 70 MW
Approx. 90% of capacity costs
Est. 1st contract year future $15,960
Est. 2nd contract year future $11,400
Est. 3rd contract year future $9,120
Est. 4th contract year future $6,840
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 (NU) 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 air emission limits for sulfur
dioxide ("SO2") and Nitrogen Oxides ("NOx") starting in 1995, mandated by the
Clean Air Act Amendments of 1990 ("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 for Merrimack #2 are specified in Administrative
Rules established by the state of New Hampshire. The NOx limits specified in
the Rules that occur during the VELCO Contract term are effective May 31,
1995.
PSNH expects to comply with the Merrimack #2 NOx limits by installing
Selective Catalytic Reduction ("SCR") equipment by May 31, 1995. The
estimated SCR capital cost is $19 million and the estimated increase in
operating costs from the SCR are $1.6 million annually. The SCR is expected
to have a negligible effect on unit fuel efficiency. The Company will share
on a pro-rata basis the SCR based on its share of the VELCO contract. The
total cost to the Company of energy generated by the Merrimack #2 unit was
3.21 cents per KWH in 1994. The 1994 annual capacity factor was 68%.
Other Purchases.
Cogeneration/Small Power Qualifying Facilities - A number of small
producers using hydroelectric, biomass, and refuse-burning generation are
currently producing energy that the Company is purchasing. For the year ended
December 31, 1994, the Company received 190,613 MWH from these sources for
which it paid $18,893,051. The Company expects to purchase approximately 42
MW in each year 1995 through 1999. The total commitment in the next five
years to purchase power from these qualifying facilities is approximately
$105.9 million.
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 facilities. Cogeneration is the production
of electricity and usable thermal energy from the same fuel.
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.
The St. Lawrence Project power was reduced to one MW in July 1994 and
will continue to be available to the Department at this level 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 1994 occurred on January 17, 1994 and equaled 414.6 MW. At the time of
this peak, the Company had a reserve margin of 31.9%. NEPOOL's peak for the
year occurred on July 21, 1994 and totaled 20,519 MW. NEPOOL had a 21%
reserve margin at the time of its 1994 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
1994, about 30% of the Company's purchased power came from renewable sources,
primarily water and wood. The Company's core business has no plans at this
time to build any new generating facilities to supply power, instead it
intends to satisfy customers' energy needs through a combination of power
purchases and energy-efficiency services. Therefore, the Company uses a
process called "integrated resource planning," or IRP, to help determine the
resources necessary to meet future power needs. IRP is an evolving, on-going
process. An interdisciplinary team representing various functional planning
area works together continuously to coordinate and integrate planning. The
primary objective of IRP is to provide reliable, least-cost energy resources
consistent with the Company's policy to protect the environment. The choice
of least-cost resources explicitly seeks a balance between traditional supply
resources and energy efficiency investments with the Company's customers.
Flexibility and diversity are investment guidelines designed to provide least-
cost resources over a broad range of possible futures.
The resource plan calls for investments in energy efficiency through the
1990's with additional investments in energy-efficiency programs or power
purchases beginning after the year 2000. 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 compared to the
alternative practice of building power plants. The resources from developers
of cogeneration projects were deferred due to decreased need. Certain power
purchases from Hydro-Quebec were deferred until 1996. Energy efficiency
investments associated with new customers and new end-uses naturally declined
during the period of reduced load growth and new deferrable efficiency
investments were postponed.
Based upon current load forecasts, the Company expects to be able to
satisfy its load requirements into the first decade of the next century
through its ownership in various generating facilities and purchases from
various other New England, New York, Canadian utilities, Independent Power
Producers, and Conservation and Load Management. Current load and capacity
forecasts for NEPOOL indicate adequate reserves and availability of power for
the region as a whole and the Northeast well past the year 2000.
TRANSMISSION
Vermont Electric Power Company, Inc.
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 Item 8 herein for a discussion of the 1985 Four Party
Agreement between the Company, VELCO and two other major distribution
companies in Vermont.
VELCO provides transmission services for the State of Vermont, acting by
and through the Department, and for all of the electric distribution utilities
in the State of Vermont. VELCO is reimbursed for its costs (as defined in the
agreements relating thereto) for the transmission of power for such entities.
The Company, as the largest electric distribution utility in Vermont, is the
major user of VELCO's transmission system.
The Company owns 34,083 shares (56.8%) of the Class B common stock of
VELCO, the balance being owned by other Vermont utilities. Each share of
Class B common stock has one vote. The Company also owns 46,624 shares
(46.6%) of the Class C preferred stock of VELCO, the balance being owned by
other Vermont utilities. Shares of Class C preferred stock have no voting
rights except the limited right to vote VELCO's shares of common stock in
Vermont Electric Transmission Company, Inc. 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, 1994 and
125,000 shares of Class C preferred stock, of which 100,000 shares were
outstanding at December 31, 1994. On that date there were authorized and
outstanding three issues of First Mortgage Bonds, aggregating $37,999,000,
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
1995 to transmit power to Vermont utilities. The costs of such facilities are
presently estimated at $2,910,000 including allowance for funds used during
construction calculated at a rate of approximately 4.7%. For a description of
VELCO's properties, see "VELCO" under Item 2.
Management.
In 1957 VELCO entered into an agreement (the "Three-Party Agreement")
whereby the Company and Green Mountain agreed that, if VELCO transmits firm
power owned by it (which it does not now do), they would have the right to
purchase all such firm power not sold to others with their consent and the
obligation to pay (in agreed proportions) amounts sufficient, together with
VELCO's revenues from other sources, to pay all VELCO's operating expenses,
debt service and taxes. In connection with the transfer to VELCO of
entitlements of the output of the Vermont Yankee plant, the Company and Green
Mountain entered into a Three-Party Transmission Agreement, dated November 21,
1969, as amended, whereby they have agreed to pay transmission charges thereon
in an aggregate amount sufficient, with VELCO's other revenues, to pay all of
VELCO's expenses including capital costs. VELCO's Bonds are secured by a
first mortgage on the major part of VELCO's transmission properties and by the
assignment to the Trustee of the Three-Party Agreement, the Three-Party
Transmission Agreement and certain other contracts as specified in the VELCO
Indenture. See Item 8 herein for information relating to the 1985 Four-Party
Agreement.
Vermont Electric Transmission Company, Inc.
In connection with the importing of Canadian power, VELCO has created a
wholly owned subsidiary, 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, 1994) 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, 1994 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
1993 and 1994 were $9.9 million and $6.2 million, respectively, and are
expected to be approximately $6.0 million in 1995. The amount of expenditures
will be adjusted annually, based on the cost-effectiveness of programs
compared to other options.
The October 31, 1994 PSB Rate Order allowed the recovery of $13.9 million
of C&LM expenditures and lost revenues, deferred since the prior PSB rate
order which became effective September 1, 1991, over a five-year period
beginning November 1, 1994 through October 31, 1999. The Company had
requested the recovery of $14.6 million of such deferred C&LM expenditures and
lost revenues. Accordingly, during 1994, the Company wrote-off approximately
$.7 million of costs disallowed by the PSB in its October 31, 1994 Rate Order.
For additional information regarding the PSB Rate Order, see Item 7 herein.
In addition, the Company is involved in several cases in Vermont related
to C&LM activities including the role of fuel-switching as a C&LM resource and
the level of externalities to be recognized in Integrated Resource Planning
and C&LM cost-effectiveness testing. On October 31, 1994, the Company also
filed its Integrated Resource Plan, which describes the Company's long-term
resource acquisition plans including C&LM. Currently, the Company is involved
in cooperative efforts with the DPS to settle many issues related to C&LM.
Currently the New Hampshire Public Utilities Commission (NHPUC) staff and
the Company have reached agreement on most of the issues concerning the 1995
C&LM expenditures and related lost revenues for the Company's wholly owned New
Hampshire subsidiary, Connecticut Valley Electric Company Inc. These
expenditures and lost revenues are recovered along with shareholder incentives
for 1994 program activity through a C&LM percentage adjustment clause of
January 1 through December 31, 1995. The NHPUC has approved these rates in an
interim Order dated December 13, 1994.
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,
through its wholly owned subsidiaries, has 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 Item 8 herein.
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, 1994 the Company
and its wholly owned subsidiaries employed 696 persons, of which 241 are
represented by the union. On December 31, 1992, the Company and its employees
represented by the union agreed to a three-year contract, which 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 and recorded an
obligation related to a Voluntary Retirement Program (VRP). The VRP was
accepted by 42 employees. The estimated benefit obligation for the VRP as of
December 31, 1994 is about $4.5 million. This amount consists of pension
benefits and postretirement medical benefits of $2.2 million and $2.3 million,
respectively. Additionally, 32 employees accepted a Voluntary Severance
Program (VSP) offered by the Company. Eligible employees had until April 22,
1994 to apply. The Company also announced a layoff of 20 employees on May 9,
1994. VSP and layoff obligations of $.8 million and $.2 million,
respectively, were recorded in the second quarter of 1994. At December 31,
1994, the benefit obligation for the VSP was about $96,000. The VRP, VSP and
layoff combined with attrition since mid-1993, yields a total work force
reduction of approximately 14%. In the October 31, 1994 PSB Rate Order, the
Company was allowed rate recovery of this restructuring cost over a five-year
period. The unamortized balance of these costs was approximately $4.8 million
at December 31, 1994.
SEASONAL NATURE OF BUSINESS
The Company experiences its heaviest loads in the colder months of the
year. Winter recreational activities, longer hours of darkness and heating
loads from cold weather usually cause the Company's peak of electric MWH sales
to occur in January or late December. For additional information regarding
the seasonal nature of business see Item 8 herein.
Item 2. Properties.
The Company. The Company's properties are operated as a single system
which is interconnected by transmission lines of VELCO, New England Power
Company and PSNH. The Company owns and operates 21 small generating stations
with a total current nameplate capability of 66,370 KW, has a 1.78% joint-
ownership interest in an oil generating plant in Maine, has a 20% joint-
ownership interest in a wood, gas and oil-fired generating plant in Vermont,
has a 1.73% joint-ownership interest in a nuclear generating plant in
Connecticut, has a 46.08% joint-ownership interest in a transmission
interconnection with Hydro-Quebec in Vermont and leases and operates two hydro
generating stations from wholly owned subsidiaries, Bradford and East Barnet,
1,500 KW and 2,200 KW, respectively.
The electric transmission and distribution systems of the Company include
about 614 miles of overhead transmission lines, about 7,199 miles of overhead
distribution lines and about 213 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 427 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; on the south with the
facilities of Vermont Yankee; and on the north with lines of Hydro-Quebec
through a converter station and tie line jointly owned by the Company and
several other Vermont utilities.
VETCO. VETCO has approximately 52 miles of high voltage DC transmission
line connecting at the Quebec-Vermont border in the Town of Norton, Vermont
with the transmission line of Hydro-Quebec and connecting at the Vermont-New
Hampshire border near New England Power Company's Moore hydro-electric
generating station with the transmission line of New England Electric
Transmission Corporation, a subsidiary of New England Electric System.
Item 3. Legal Proceedings.
On March 20, 1992, Sunnyside Cogeneration Associates filed suit in the
United States District Court for the District of Vermont against the Company,
CV Energy Resources, Inc. (CVER) and a subsidiary of CVER alleging damages in
excess of five million dollars resulting from the parties inability to come to
agreement on the terms of CVER's proposed investment in the plaintiff's waste
coal cogeneration facility under construction in Sunnyside, Utah. The Company
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.
On December 30, 1994 the Company and its Board of Directors were named as
defendants in a complaint filed in the United States District Court for the
District of Vermont by three shareholders. The complaint alleges among other
things, (i) that F. Ray Keyser, Jr., Chairman of the Company's Board of
Directors, violated Section 8 of the Clayton Act, 15 U.S.C. Subchapter 19,
which precludes certain interlocking directorships, (ii) that Mr. Keyser
violated his fiduciary duties to the Company's stockholders by acquiring and
operating a series of businesses in competition with the Company without
offering those business opportunities to the Company, (iii) that the remaining
individual defendants violated their fiduciary duties to the Company's
stockholders by failing to analyze, or to cause management to analyze,
diversification into propane and fossil fuels, and by failing to make the
Company an effective competitor of alternative fuel companies, and (iv) that
the Company violated the applicable provision of the Vermont General
Corporation Law by failing to provide a list of the Company's stockholders.
The complaint seeks an unspecified amount of damages (including treble damages
against Mr.Keyser), attorney's fees and costs, a list of the Company's
stockholders, and a court order to enjoin the defendants from alleged
continuing violations of the law. Each of the individual defendants and the
Company itself deny the allegations against them and intend to vigorously
defend the complaint.
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 1994.
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
1994
First quarter.............. $ 22 $ 18 3/8
Second quarter............. 19 1/8 14 1/4
Third quarter.............. 15 1/2 12 1/8
Fourth quarter............. 14 1/2 12 3/8
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
(b) As of December 31, 1994, there were 16,961 holders of the Company's
common stock, $6 par value.
(c) Common stock dividends have been declared quarterly. Cash dividends
of $.355 per share were paid for all quarters of 1994 and 1993.
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, 1994, the Common Stock Equity
of the Company was 54.4% of total capitalization.
For additional information regarding dividend payment level and dividend
restrictions see Item 8 herein.
Item 6. Selected Financial Data.
(Dollars in thousands, except per share amounts)
1994 1993 1992 1991 1990
For the year
Operating revenues $277,158 $279,389 $275,375 $233,469 $231,565
Net income $ 14,800* $ 21,292 $ 21,422 $ 18,576 $ 17,531
Earnings available for common stock $ 12,662* $ 18,634 $ 18,764 $ 17,514 $ 16,533
Consolidated return on average
common stock equity 7.2%* 11.0% 11.8% 11.8% 12.0%
Earnings per share of common stock $1.08* $1.64 $1.71 $1.65 $1.62
Cash dividends paid per share of
common stock $1.42 $1.42 $1.39 $1.39 $1.37
Book value per share of common stock $14.56 $15.03 $14.21 $14.03 $13.68
Net cash provided by operating
activities $ 49,410 $ 36,833 $ 48,904 $ 42,033 $ 23,591
Dividends paid $ 18,845 $ 18,112 $ 18,174 $ 15,677 $ 14,978
Construction and plant expenditures $ 22,621 $ 20,519 $ 20,503 $ 18,950 $ 21,202
Conservation and Load Management
expenditures $ 6,159 $ 9,874 $ 3,539 $ 1,946 $ 1,534
At end of year
Long-term debt $120,157 $122,419 $107,879 $130,163 $129,790
Total capitalization
(excluding current portion of debt) $318,995 $331,309 $302,023 $316,897 $286,424
Total assets $490,399 $480,150 $451,052 $430,748 $406,426
* Net income includes non-recurring charge-offs of $4,336,000 (net of tax benefit of $1,785,000). For a detail of
these charge-offs see Management's Discussion and Analysis of Financial Condition and Results of Operations.
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations.
Earnings Overview.
The Company's earnings per share of common stock declined by 34% in 1994
to $1.08 from $1.64 per share in 1993. The return on common equity was 7.2%
for 1994 and 11.0% for 1993. Earnings per share of common stock and return on
common equity for 1992 were $1.71 and 11.8%, respectively. In 1992, earnings
and earnings per share of common stock were reduced by approximately $3.0
million and $.27, respectively, for an anticipated environmental cleanup.
Weak sales, increased cost of operations and fourth quarter charges, discussed
below and described in results of operations, are primarily responsible for
reduced earnings for 1994.
During the fourth quarter of 1994, the Company incurred three non-
recurring charges. The first resulted from cost disallowances associated with
the Vermont Public Service Board (PSB) Rate Order described below, which
reduced after tax earnings and earnings per share of common stock by
approximately $1.8 million and $.16, respectively. The second resulted from
the Company's decision to discontinue its proposed new headquarters office
building which reduced after tax earnings and earnings per share of common
stock by $1.7 million and $.14, respectively. The third resulted from
writing down SmartEnergy Service Inc.'s investment in Green Technologies,
Inc.'s common stock to reflect management's estimate of the decline in value
of the investment. As a result, after-tax earnings and earnings per share of
common stock were reduced by $.8 million and $.07, respectively.
Absent the non-recurring charges, net income and earnings per share of
common stock would have been as follows (dollars in thousands):
Year Ended December 31
1994 1993 1992
Net income as reported $14,800 $21,292 $21,422
Non-recurring charges, net of taxes 4,336 - 2,965
------- ------- -------
Net income before non-recurring charges $19,136 $21,292 $24,387
======= ======= =======
Earnings per share of common stock
before non-recurring charges $1.45 $1.64 $1.98
As a result of these non-recurring charges, the Company earned an 8.4%
return on its Vermont utility business and a 1.1% return on non-utility
investments. The combined non-utility investments return of 1.1% resulted
from a 4.9% return from Catamount Energy Corporation and a 34.2% loss from
SmartEnergy Services, Inc. primarily caused by the write down of its
investment in Green Technologies, Inc. See Item 8 herein for additional
details on the Company's non-utility investments.
A PSB Rate Order dated October 31, 1994, subsequently amended, allowed
the Company a base retail rate increase of 5.07% or approximately $10.2
million effective with service rendered November 1, 1994. The Company had
filed for an 8.9% or $17.9 million increase in its base retail rates in
February 1994. The Rate Order also lowered the allowed rate of return on the
Company's common stock equity from 12% to 10%. The allowed return on common
stock equity is after deducting a .75% penalty based on the PSB's conclusions
that there had been "mismanagement of power supply options" and because of
"the Company's failed efforts to acquire all cost-effective energy efficiency
resources." The Company disagrees with the PSB's conclusion.
Recognizing the need for financial flexibility in the face of the
increasingly competitive marketplace, the Company's board of directors
announced, on November 8, 1994, a new corporate strategy which includes a
dividend targeted at approximately 60% of earnings; a program to purchase up
to 2 million shares of its outstanding common stock in open market
transactions; a new strategic plan to provide earnings growth and cost
stability; and a further reduction in corporate spending to ensure that only
projects and activities critical to reliable, cost-effective operations are
funded.
These actions are part of a plan to both control costs and rates, and to
help position the Company for growth and success into the next century in a
more competitive, price sensitive environment. These moves will allow the
Company to retain more capital in the business, provide increased financial
flexibility and assure the Company's ability to take advantage of
opportunities for growth.
Results of Operations.
Operating revenues and MWH sales A summary of MWH sales and operating
revenues for 1994 and 1993 (and the related percentage changes from 1993) is
set forth below:
Percentage Percentage
MWH Sales Increase Revenues (000's) Increase
1994 1993 (Decrease) 1994 1993 (Decrease)
Residential 954,329 958,102 (.4) $ 99,991 $ 99,101 .9
Commercial 860,474 842,694 2.1 89,209 86,553 3.1
Industrial 391,928 400,117 (2.0) 30,002 30,741 (2.4)
Other retail 7,564 7,480 1.1 1,744 1,706 2.2
--------- --------- -------- --------
Total retail sales 2,214,295 2,208,393 .3 220,946 218,101 1.3
Less: DPS sales - 25,714 (100.0) - 1,558 (100.0)
--------- --------- -------- --------
Total Company retail sales 2,214,295 2,182,679 1.4 220,946 216,543 2.0
--------- --------- -------- --------
Resale sales:
Firm 17,469 62,564 (72.1) 634 2,747 (76.9)
Entitlement 834,304 908,819 (8.2) 37,220 42,417 (12.3)
Other 642,802 286,249 124.6 14,201 6,445 120.3
--------- --------- -------- --------
Total resale sales 1,494,575 1,257,632 18.8 52,055 51,609 .9
--------- --------- -------- --------
Other revenues - - - 4,157 5,162 (19.5)
--------- --------- -------- --------
Deferred revenues - - - - 6,075 (100.0)
--------- --------- -------- --------
Total 3,708,870 3,440,311 7.8 $277,158 $279,389 (.8)
========= ========= ======== ========
Year-to-year fluctuations in total retail MWH sales are primarily
affected by customer growth, Conservation and Load Management (C&LM) programs
as well as relative prices of alternate energy sources, weather patterns and
conservation induced by price changes and income elasticity responses of
customers. Total retail MWH sales for 1994 were relatively flat compared to
1993, reflecting weak sales due to the state's slow economic growth and the
effectiveness of C&LM programs. Although the Company was granted a 5.07%
retail rate increase effective with service rendered November 1, 1994, retail
revenues increased only 1.3%. Total Company retail MWH sales increased 1.4%
and related revenues increased 2.0%. The increase is principally attributable
to the September 1, 1993 change in power supplied to retail customers by the
Company rather than as previously provided by the DPS. The impact was to
increase retail sales and revenues by 25,714 MWH and $1.6 million in 1994.
The increase in retail revenues was offset by a decrease in other
revenues reflecting elimination of the fee previously charged to the DPS for
delivery of power and for providing billing and collection services.
Due to current market conditions, some of the Company's firm resale
customers chose not to extend their contracts beyond October 1993. As a
result, firm resale MWH sales and revenues declined for 1994 and 1993.
However, one of those customers opted to purchase power from the Company based
on market rates.
Entitlement MWH sales and revenues decreased 8.2% and 12.3%,
respectively, due to reduced sell-back of the Hydro-Quebec Schedule C-1 and C-
2 power offset by increased sales made in conjunction with a swap arrangement
with Commonwealth Electric as well as sales to UNITIL.
Other resale sales for 1994 increased 356,553 MWH and related revenues
increased $7.8 million. These sales, made on a short-term basis, include
sales to NEPOOL and other utilities in New England.
The Company continues to make every effort to maintain or increase resale
sales despite the weak market for capacity and energy in the region.
Deferred revenues of $6.1 million in 1993 relate to the recognition of
revenues deferred from 1991 to 1993.
The table below analyzes the components of increases or decreases in
revenues (including DPS sales) compared to the prior year (dollars in
thousands):
1994 1993
Revenue increase (decrease) from:
Retail MWH sales $ 826 $(2,395)
Retail rates 2,019 (84)
Changes in firm resale sales (2,113) (888)
Changes in entitlement sales (5,197) (983)
Changes in other resale sales 8,006 14
Changes in other revenues (70) 306
Deferred revenues (6,075) 6,075
------- -------
Net increase (decrease) over prior year $(2,604) $ 2,045
======= =======
The minimal increase in retail MWH sales described above resulted in an
$.8 million increase in retail revenues. The increase in retail rates of $2.0
million is due to the 5.07% retail rate increase that became effective with
service rendered November 1, 1994. Retail MWH sales in 1993 were lower by
1.3%, compared to 1992 resulting in a $2.4 million decrease in retail
revenues.
The decrease in entitlement sales for 1993 compared to 1992 is due to the
scheduled refueling and unplanned shutdowns of Vermont Yankee reducing sales
to UNITIL and Commonwealth Electric under a swap arrangement. In addition, in
1992, the Company was able to sell a portion of its Vermont Yankee entitlement
to Public Service Company of New Hampshire.
Purchased power The Company purchases approximately 90% of its power needs
under several contracts of varying duration. Over 30% of these purchases are
from affiliated companies whereby the Company receives its entitlement share
of the output. The Company's purchased power portfolio assures that a mix of
sources and fuel types are available to meet the Company's long-term load
growth while providing short and intermediate term opportunities to purchase
or sell capacity and energy to reduce overall power costs. The percentages of
the Company's energy sources from certain long-term commitments and Company-
owned generating units were as follows:
Year Ended December 31
1994 1993 1992
Nuclear generating companies 39% 34% 34%
Canadian imports 20 28 25
PSNH-coal 7 8 7
Company-owned hydro 5 5 5
Jointly owned units 5 4 4
Small power producers 5 5 3
Other sources 19 16 22
--- --- ---
100% 100% 100%
=== === ===
The Company has equity ownership interests in four nuclear generating
companies: Vermont Yankee (VY), Maine Yankee (MY), Yankee Atomic (YA) and
Connecticut Yankee (CY).
The VY nuclear plant, which provides approximately one-third of the
Company's power supply, was unavailable from March 6 through April 21, 1992
and from August 27 through October 24, 1993 due to its scheduled refueling
outages, and had unscheduled outages from April 7 to April 16, 1993 and
December 6 to December 20, 1993.
The MY plant was shut down for refueling and maintenance from February 14
through April 19, 1992 and from July 30 through October 13, 1993.
See Note 2 to the Consolidated Financial Statements for details related
to YA.
The CY plant was shut down for refueling and for an extended outage from
October 17, 1991 through March 18, 1992 and for a scheduled refueling outage
from May 15 through July 21, 1993.
There were no scheduled refueling outages and no major unscheduled
outages during 1994.
During scheduled refueling outages, the Company purchases more costly
replacement energy from NEPOOL and other sources to satisfy energy needs. In
accordance with current rate-making treatment, the Company defers and
amortizes to expense over their respective fuel cycles the incremental
replacement energy and maintenance costs associated with these refueling
outages for the Yankee plants and the Millstone #3 jointly owned nuclear
generating unit. During 1993, the Company deferred $2.4 million and $6.5
million of replacement energy and capacity costs, respectively, for VY, MY, CY
and Millstone #3.
In 1984, the Company and other Vermont utilities signed a long-term
purchase power contract with the DPS for 150 MW of power provided by Hydro-
Quebec. During 1987, the Company and eight other Vermont utilities signed a
long-term purchased power contract with Hydro-Quebec for up to 450 MW of power
until 2020. Approval of the 450 MW contract was received in 1990. See Note
13 to the Consolidated Financial Statements for further details related to the
Hydro-Quebec power contracts.
Under a 30-year contract, which expires in 1998, the Company purchases
46.98 MW of capacity from Merrimack #2, a coal-fired generating plant owned by
Northeast Utilities (NU). Vermont Electric Power Company, Inc., representing
Vermont utilities, and NU negotiated an agreement which assures the
continuation of this contract through 1998 under its original terms, thereby
resolving past uncertainty relating to the contractual price of capacity and
the availability of the unit to the Company.
The Company also owns 20 hydroelectric generating units which have a
total nameplate capability of 41.2 MW and two gas-fired and one diesel-peaking
units with a combined nameplate capability of 28.9 MW. In addition, the
Company maintains joint-ownership interests in Joseph C. McNeil, a 53 MW wood,
gas and oil-fired unit; Wyman #4, a 619 MW oil-fired unit; and Millstone #3,
an 1149 MW nuclear unit. Millstone #3 was shut down from July 31 through
November 7, 1993 for a refueling outage. The Company's percentage ownership
in these units is 20%, 1.78% and 1.73%, respectively.
The Company, under long-term contracts, purchases power from a number of
small power producers who own qualifying facilities under the Public Utility
Regulatory Policies Act of 1978. These qualifying facilities produce energy
using hydroelectric, wood, biomass, and refuse-burning generation. During
1994, the Company purchased 34.4 MW of which approximately 30.1 MW is
associated with the Vermont Power Exchange and 3.9 MW with a New
Hampshire/Vermont solid waste plant.
The Company engages in purchases and sales with other electric utilities
and with NEPOOL to take advantage of immediate pricing and other market
conditions. These purchases are included in Other sources in the table above.
The net cost components of purchased power for the past three years were
as follows (dollars in thousands):
1994 1993 1992
Units Amount Units Amount Units Amount
Purchased and produced:
Capacity (MW) 568 $ 83,677 496 $ 86,857 478 $ 84,346
Energy (MWH) 3,544,563 59,485 3,338,298 59,726 3,481,297 55,514
Production fuel (MWH) 381,819 1,932 313,020 1,737 324,478 2,201
-------- -------- --------
Total purchased power and
production fuel costs 145,094 148,320 142,061
Entitlement and other
resale sales (MWH) 1,477,106 51,421 1,195,068 48,862 1,386,868 51,259
-------- -------- --------
Net purchased power and
production fuel costs $ 93,673 $ 99,458 $ 90,802
======== ======== ========
Purchased capacity costs decreased $3.2 million for 1994 resulting from a
$15.7 million decrease in price offset by an increase of 14.5% or $12.5
million in the amount of MW purchased. These variances are primarily due to
the absence of refueling outages for Vermont Yankee.
The increase in total purchased capacity costs for 1993 is due to an
increase in MW purchased, primarily from small power producers.
In total, energy costs for 1994 are about the same as 1993. Cost per MWH
purchased decreased 6.2% or $3.9 million offset by an increase of 6.2% or
$3.7 million in the amount of MWH purchased.
Total energy costs increased $4.2 million for 1993 primarily due to a
$6.5 million increase in price offset by a decrease of $2.3 million relating
to a 4.1% decrease in the amount of MWH purchased. However, average cost per
MWH purchased increased by 12.2%. The higher average cost is primarily due to
increased MWH purchased from small power producers mandated by Federal and
state legislation.
Energy costs are directly related to the variable prices of oil, nuclear
fuel and coal but more importantly, to the proportion of the Company's
purchased energy that comes from each of these fuel sources. The swap
arrangement with Commonwealth Electric of Canal #2 power has increased the
Company's reliance on oil as a source of electricity. Also, some Canadian
purchased power contracts are tied to fossil fuel price indices. This will
increase the Company's exposure to the variability of oil price volatility.
The Company is responsible for paying its entitlement percentage of
decommissioning costs for VY, CY, MY and YA as well as its joint ownership
percentage of decommissioning costs for Millstone #3. See Notes 2 and 13 to
the Consolidated Financial Statements. Recently, the staff of the Securities
and Exchange Commission has questioned certain current accounting practices of
the electric utility industry, including the Company, regarding the
recognition, measurement and classification of decommissioning costs for
nuclear generating stations in financial statements of electric utilities. In
response to these questions, the Financial Accounting Standards Board has
agreed to review the accounting for nuclear decommissioning costs. If current
electric utility industry accounting practices for such decommissioning costs
are changed it is possible that annual provisions for decommissioning costs
could increase, the total estimated costs for decommissioning could be
recorded as a liability, and income from external decommissioning trusts could
be reported as investment income instead of a reduction to decommissioning
expense. The Company does not believe that such changes, if required, would
have an adverse effect on results of operations due to its ability to recover
decommissioning costs through the regulatory process. See Liquidity and
Capital Resources - Competition, for related information.
The increase in production fuel costs of $.2 million for 1994 results
from a 22.0% or 68,799 MWH increase in the amount of MWH generated mostly by
one of the Company's jointly owned units, Millstone #3.
Production fuel costs decreased 21.1% or $.5 million in 1993, due to
lower generation by the Company's jointly owned units.
In order to optimize its power mix for baseload, intermediate and peaking
power, the Company engages in sales and purchases with other electric
utilities, primarily in New England and with NEPOOL. These transactions
typically take advantage of immediate pricing and other market conditions.
The profits from these transactions are used to reduce revenue requirements
for rate-making purposes.
As stated earlier, the Company is making every effort to maintain or
increase these sales despite the weak resale market for excess capacity and
energy in the region.
The Company's forecast indicates that net purchased power and production
fuel costs will be approximately $103.5, $116.3, and $136.0 million for the
period 1995 through 1997.
Production and transmission The 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 the 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 Phase II project cost is approximately
$487 million. The Company pays 5.132% of support costs or about $2.7 million
annually. Also, the Company is obligated to pay a 4.421% share of the Phase I
Hydro-Quebec capital costs or about $.5 million annually. Under the support
agreement, the Company is eligible for savings associated with certain energy
transactions by NEPOOL, which offset the Company's support cost obligations.
Variances for production and transmission expenses for 1994 and 1993 were
minimal.
Other operation expenses Other operation expenses increased 13.2% or $4.8
million primarily due to the charge-off of approximately $2.9 million in costs
related to the proposed new corporate headquarters office building, an
increase in pension and benefit costs and regulatory commission expenses.
Other operation expenses decreased $2.2 million for 1993 primarily due to an
environmental reserve of $4.9 million established in December 1992 related to
estimated costs associated with the cleanup of coal tar deposits discovered at
the Company's Cleveland Avenue site, offset in part by the recognition of a
postretirement benefit obligation in accordance with Statement of Financial
Accounting Standards (SFAS) No. 106 effective January 1, 1993. For detailed
information on SFAS No. 106, see Note 10 to the Consolidated Financial
Statements and for a complete disclosure on environmental matters, see Note 13
to the Consolidated Financial Statements.
Depreciation The increases in depreciation expense for 1994 and 1993 are due
to property additions and the installation of new computer systems in 1992 and
1993.
Income taxes Federal and state income taxes fluctuate with the level of
pretax earnings. These taxes decreased for 1994 as a result of lower pre-tax
earnings. However, the decrease was offset by the write-off of $1.6 million
of SFAS No. 109 deferred tax assets which were expected to be collected from
customers through rates. Recovery of these taxes was disallowed by the PSB in
its October 31, 1994 Rate Order described in Earnings Overview.
During 1993, the Company recognized additional accumulated deferred
income taxes of approximately $15 million and a net corresponding asset from
customers of approximately $15 million reflecting future revenues that will be
required when the temporary differences reverse and are settled in rates.
Also, due to the Revenue Reconciliation Act which was passed on August 10,
1993, income tax expense increased by approximately $.3 million for the year
1993.
Other income and deductions Equity in earnings of affiliates decreased 14.3%
for 1994, as compared to 1993. The decrease is attributable to a lower rate
of return allowed by the Federal Energy Regulatory Commission to some of the
Company's nuclear generating affiliates.
The increase in allowance for equity and borrowed funds used during
construction for 1994 is due to an increase in capital expenditures and also
due to higher rates used for capitalization of these funds. In 1993, AFDC was
lower than in 1992 due to lower rates used for capitalization of these funds.
Other income (expenses), net, decreased approximately $.9 million for
1994 compared to 1993. During the fourth quarter of 1994, the Company wrote-
down its investment in Green Technologies, Inc. by approximately $1.3 million
to reflect management's estimate of the decline in value of the investment.
This write-down is partially offset by higher income from non-utility
subsidiaries as well as higher interest on temporary cash investments due to a
combination of higher investment levels and interest rates during 1994.
Other income (expenses), net, decreased for 1993 due to lower prevailing
interest rates and lower levels of investments resulting in decreased earnings
from temporary cash investments offset by increased income from non-utility
operations.
Interest on long-term debt The increase in interest on long-term debt for
1994 results from the issuance of $43 million of First Mortgage Bonds in
December 1993. Interest on long-term debt decreased $3.0 million for 1993
primarily due to refinancing First Mortgage Bonds at lower interest rates.
Other interest expense Other interest expense increased approximately
$.4 million for 1994 due to the 1993 FERC settlement related to certain
wholesale customers. Other interest expense decreased $.9 million for 1993
mainly due to a FERC settlement related to certain wholesale customers. The
decrease was offset in part by an increase in interest expense due to higher
levels of short-term borrowings outstanding during 1993.
Cash Dividends Declared
Preferred
In January 1994, the Company redeemed 280,000 shares of preferred stock
9% dividend series at a premium of $.25 per share. This redemption resulted
in a decrease in preferred dividends declared for 1994 compared to 1993.
Common
The increase in common dividends declared for 1994 results from an
advanced quarterly common dividend declaration in December 1994 payable
February 15, 1995. As a result, the accompanying Consolidated Financial
Statements reflect five quarterly dividend declarations in 1994. The December
1994 declaration reflects the 44% reduction in future dividends paid per
share.
The decrease in common dividends declared for 1993 as compared with 1992
is due to an advanced quarterly common dividend declaration in November 1992
payable February 12, 1993.
Liquidity and Capital Resources
Competition As described in Note 1 to the Consolidated Financial Statements,
management believes that the Company meets the requirement of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation", but continues to
evaluate significant changes in the regulatory and competitive environment to
ensure and assess the Company's overall consistency with the criteria of SFAS
No. 71. In the event the Company determines that it no longer meets the
criteria for following SFAS No. 71, the accounting impact would be an
extraordinary non-cash charge to operations of an amount that could be
material. Although these conditions do not currently exist, the Company
anticipates that in the future competition will place pressure on both unit
sales and the price the Company can charge. As a result, increased
competitive pressure in the electric utility industry may restrict the
Company's ability to establish prices to recover embedded costs and may lead
to a significant change in the manner in which rates are set by regulators
from cost-based regulation to a different form of regulation that approximates
market conditions. Singly or together these events may give rise to the
discontinuance of SFAS No. 71 and, in addition, could diminish the Company's
ability to recover its embedded costs of providing service.
Construction The Company's liquidity is primarily affected by the level of
cash generated from operations, power contracts, and the funding requirements
of its ongoing construction and C&LM programs. Cash flows from operating
activities after dividends paid provided approximately $30.6 million in 1994,
$18.7 million in 1993 and $30.7 million in 1992.
Consistent with the new Corporate Strategy announced by the Company's
Board of Directors (Board) on November 8, 1994, construction expenditures over
the next five years will be directed toward the funding of projects and
activities critical to reliable, cost effective operations. In light of this,
the Company is deferring some planned expenditures and also decided to
discontinue its proposed new headquarters office building. Accordingly,
during the fourth quarter of 1994, the Company wrote-off approximately $2.9
million of pre-tax costs related to the new headquarters office building.
Excluding allowance for funds used during construction, construction
expenditures plus expenditures for the Company's C&LM programs are estimated
to average between $20-23 million for each of the next five years. The
Company's goal is to finance approximately 100% of these annual expenditures
with funds generated from operations.
Financing and Capitalization
Utility The level of short-term borrowings fluctuates based on seasonal
corporate needs, the timing of long-term financings and market conditions.
Short-term borrowings are supported by committed lines of credit and
uncommitted loan facilities with several banks totaling $43.25 million.
Short-term borrowings generally are reduced when long-term debt or equity
securities are issued. In December 1993, the Company issued $43 million of
long-term debt, of which $14.5 million replaced First Mortgage Bonds redeemed
in October 1993 and $4.325 million replaced First Mortgage Bonds redeemed in
January 1994. The balance was used to reduce short-term debt outstanding. In
December 1994, the Company's wholly owned subsidiary, Connecticut Valley
Electric Company Inc., issued a promissory note of $2.5 million under a five-
year loan agreement. The proceeds were used to settle its 9 1/2% note of $2.5
million held by the parent company. In the past, the Company has been able to
finance its construction and C&LM programs and it expects to meet future
commitments.
In 1988, the Company sold a $12 million interest in certain customers'
accounts receivable and unbilled revenues. Under the sales of accounts
receivable agreement the Company can sell an additional $8 million of accounts
receivable if certain accounts receivable ratio tests are satisfied. The
original sale of customer accounts receivable and unbilled revenue was for a
two-year period with an option that the Company may request, on each
anniversary date, an extension for an additional year.
On November 8, 1994, the Board announced a new dividend policy that
targeted future dividends at 60% of earnings. In light of the new policy, the
current annual dividend of $1.42 was reduced 44% to $.80 effective with the
first quarter dividend paid in February 1995. Accordingly, on December 5,
1994, the Board declared a quarterly common stock dividend of $.20 per share
payable February 15, 1995 to shareholders of record on January 31, 1995. The
dividend payment level will be reviewed regularly in light of capital needs,
projected earnings' levels and other relevant factors. Also, the Board
authorized the purchase of up to 2 million shares of its outstanding common
stock in open market transactions. As of December 31, 1994, the Company had
purchased 56,400 shares at an average price of $12.98 per share. These
transactions are recorded as treasury stock, at cost, in the Company's
Consolidated Balance Sheet.
As of February 8, 1995, the Company had purchased 74,700 shares at an
average price of $12.99 per share.
In January 1994, the Company redeemed $7 million of the 9.00% Series
Preferred Stock, $25 Par Value.
Beginning in August 1994, Dividend Reinvestment and Common Stock Purchase
Plan, and Employee Stock Ownership Plan requirements were satisfied by the
purchase of shares of common stock on the open market.
The Company's capital structure ratios (including amounts of long-term
debt due within one year) for the past three years were as follows:
December 31
1994 1993 1992
Common stock equity 53% 52% 51%
Preferred stock 9 10 11
Long-term debt 38 38 38
--- --- ---
100% 100% 100%
=== === ===
On July 21, 1994 and on August 5, 1994, Duff & Phelps, Inc. (Duff &
Phelps) and Standard & Poor's Corporation (Standard & Poor's), respectively,
lowered their rating on the Company's First Mortgage Bonds and Preferred
Stock. Duff & Phelps stated that the downgrade reflects its concerns about
the continuing recession in New England, intensifying competition in the
utility industry and excess power in the northeastern region, as well as the
Company's loss of wholesale revenues. Standard & Poor's revised its ratings
outlook on the Company to "stable" from "negative" and stated "the downgrade
reflects the Company's weak financial profile, adjusted for off-balance sheet
obligations, primarily associated with purchased power, combined with the
Company's low average business position." Standard & Poor's also stated
"restrictive Vermont regulation, the state of the Vermont economy, nuclear
asset concentration and increasing investments into non-regulated businesses
are other factors impacting the Company's business position."
Current credit ratings for the Company's securities as reaffirmed, in
mid-1994, by Duff & Phelps and Standard & Poor's are as follows:
Duff & Standard
Phelps & Poor's
First Mortgage Bonds BBB+ BBB
Preferred Stock BBB- BBB-
The decline in the Company's credit ratings will likely make the terms
and conditions of borrowing more stringent, and increase the cost of capital.
Currently, the Company does not anticipate issuing preferred stock or long-
term debt in the near future.
Non-Utility Catamount Energy Corporation, a wholly owned subsidiary of the
Company, maintains an Irrevocable Standby Letter of Credit with a bank to
borrow up to an aggregate amount of $2.3 million to replace its share of cash
in the Appomattox Cogeneration Limited Partnership's Project Debt Service
Reserve Fund. This Letter of Credit is for a one-year term with annual
extensions available and requires fees totaling 2.527% of credit available.
SmartEnergy Services, Inc., also a wholly owned subsidiary of the
Company, maintains a $1.0 million revolving line of credit with a bank to
provide working capital and financing assistance for investment purposes.
Financial obligations of the non-utility wholly owned subsidiaries are
non-recourse to the Company.
Conservation and Load Management Programs (C&LM) The primary purpose of these
programs is to offset the need for long-term power supply and delivery
resources that are more expensive to purchase or develop than customer-
efficiency programs. Expenditures in 1993 and 1994 were $9.9 million and
$6.2 million, respectively, and are expected to be approximately $6.0 million
in 1995. C&LM expenditure levels are adjusted on an ongoing basis based on
the cost-effectiveness of programs compared to other options.
The October 31, 1994 PSB Rate Order allowed the recovery of $13.9 million
of C&LM expenditures and lost revenues, deferred since the prior PSB rate
order which became effective September 1, 1991, over a five-year period
beginning November 1, 1994 through October 31, 1999. The Company had
requested the recovery of $14.6 million of such deferred C&LM expenditures and
lost revenues. Accordingly, during 1994, the Company wrote-off approximately
$.7 million of costs disallowed by the PSB in its October 31, 1994 Rate Order.
For additional information regarding the PSB Rate Order, see Earnings
Overview.
In addition, the Company is involved in several cases in Vermont related
to C&LM activities including the role of fuel switching as a C&LM resource and
the level of externalities to be recognized in Integrated Resource Planning
and C&LM cost-effectiveness testing. On October 31, 1994, the Company also
filed its Integrated Resource Plan, which describes the Company's long-term
resource acquisition plans including C&LM. Currently, the Company is involved
in cooperative efforts with the DPS to settle many issues related to C&LM.
Diversification Catamount Energy Corporation (Catamount) was formed for the
purpose of investing in non-regulated energy-related projects. Currently,
Catamount, through its wholly owned subsidiaries, has interests in four
operating independent power projects located in Rumford, Maine; East Ryegate,
Vermont; Hopewell, Virginia; and Williams Lake, British Columbia, Canada.
SmartEnergy Services, Inc. was formed for the purpose of effectively
providing reliable, energy-efficient products and services, including the
rental of electric water heaters.
Rates The Company recognizes that adequate and timely rate relief is
necessary if the Company is to maintain its financial strength, particularly
since Vermont regulatory rules do not allow for changes in purchased power and
fuel costs to be passed on to consumers through rate adjustment clauses. The
Company's practice of reviewing costs periodically will continue and rate
increases will be requested when warranted. For information regarding a PSB
Rate Order issued on October 31, 1994 and subsequently amended, see Earnings
Overview. The Company anticipates filing for future rate increases when cost
containment efforts are insufficient to offset the increasing cost of
providing service, primarily purchased power.
Inflation The annual rate of inflation as measured by the Consumer Price
Index was 2.7% for 1994 and 1993, and 2.9% for 1992. The Company's revenues,
however, are based on rate regulation that generally recognizes only
historical costs. Although the rate of inflation has eased in recent years,
it continues to have an impact on most aspects of the business.
Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements and Supplementary Data
Page No.
Report of Independent Public Accountants............................. 30
Financial Statements:
Consolidated Statement of Income for each of the
three years ended December 31, 1994............................... 31
Consolidated Statement of Cash Flows for each of
the three years ended December 31, 1994........................... 32
Consolidated Balance Sheet at December 31, 1994
and 1993.......................................................... 33
Consolidated Statement of Capitalization at
December 31, 1994 and 1993........................................ 35
Consolidated Statement of Changes in Common Stock
Equity for each of the three years ended
December 31, 1994................................................. 36
Notes to Consolidated Financial Statements......................... 37
Report of Independent Public Accountants
To the Board of Directors of
Central Vermont Public Service Corporation:
We have audited the accompanying consolidated balance sheet and statement
of capitalization of Central Vermont Public Service Corporation and its wholly
owned subsidiaries as of December 31, 1994 and 1993, and the related
consolidated statements of income, changes in common stock equity and cash
flows for each of the three years in the period ended December 31, 1994.
These financial statements are the responsibility of the company's management.
Our responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Central Vermont
Public Service Corporation and its wholly owned subsidiaries as of December
31, 1994 and 1993 and the results of their operations and cash flows for each
of the three years in the period ended December 31, 1994 in conformity with
generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Boston, Massachusetts
February 6, 1995
CONSOLIDATED STATEMENT OF INCOME
(Dollars in thousands, except per share amounts)
Year Ended December 31
1994 1993 1992
Operating Revenues $277,158 $279,389 $275,375
-------- -------- --------
Operating Expenses
Operation
Purchased power 143,162 146,583 139,860
Production and transmission 21,122 21,188 20,340
Other operation 40,691 35,933 38,131
Maintenance 12,245 11,719 11,890
Depreciation 16,478 15,402 14,408
Other taxes, principally property taxes 10,423 10,022 9,602
Taxes on income 11,934 12,496 12,102
-------- -------- --------
Total operating expenses 256,055 253,343 246,333
-------- -------- --------
Operating Income 21,103 26,046 29,042
Other Income and Deductions
Equity in earnings of affiliates 3,098 3,613 3,815
Allowance for equity funds during construction 232 35 267
Other income (expenses), net (27) 827 1,383
Benefit (provision) for income taxes 525 (276) (311)
-------- -------- --------
Total other income and deductions, net 3,828 4,199 5,154
-------- -------- --------
Total Operating and Other Income 24,931 30,245 34,196
-------- -------- --------
Interest Expense
Interest on long-term debt 9,611 8,804 11,779
Other interest 657 226 1,148
Allowance for borrowed funds during construction (137) (77) (153)
-------- -------- --------
Total interest expense, net 10,131 8,953 12,774
-------- -------- --------
Net Income 14,800 21,292 21,422
Preferred Stock Dividends Requirements 2,138 2,658 2,658
-------- -------- --------
Earnings Available For Common Stock $ 12,662 $ 18,634 $ 18,764
======== ======== ========
Average Shares of Common Stock Outstanding 11,716,926 11,383,109 10,992,123
Earnings Per Share of Common Stock $1.08 $1.64 $1.71
Dividends Paid Per Share of Common Stock $1.42 $1.42 $1.39
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)
Year Ended December 31
1994 1993 1992
Cash Flows Provided (Used) By
Operating Activities
Net income $ 14,800 $ 21,292 $ 21,422
Adjustments to reconcile net income to net cash
provided by operating activities
Deferred revenues - (7,507) -
Depreciation 16,478 15,402 14,408
Write-down investment 1,332 - -
Write-off corporate headquarters costs 2,857 - -
Deferred income taxes and investment tax credits 3,522 9,615 2,652
Allowance for equity funds during construction (232) (35) (267)
Net deferral and amortization of nuclear
replacement energy and maintenance costs 5,353 (3,797) (135)
Amortization of property losses 686 1,262 119
Amortization of nuclear fuel 613 515 547
Amortization of restructuring costs 632 - -
(Increase) decrease in accounts receivable (1,598) 1,127 (823)
Increase (decrease) in accounts payable (1,298) (3,475) 1,433
Increase (decrease) in accrued income taxes 3,209 (2,991) 3,179
Decrease in other working capital items 1,916 2,028 1,162
Other, net 1,140 3,397 5,207
-------- -------- --------
Net cash provided by operating activities 49,410 36,833 48,904
-------- -------- --------
Investing Activities
(Increase) decrease in temporary investments (4,724) 597 17,978
Construction and plant expenditures (22,621) (20,519) (20,503)
Conservation and load management expenditures (6,159) (9,874) (3,539)
Investments in affiliates 150 290 269
Non-utility investments 606 (7,425) (13,536)
Other investments, net (423) (382) (391)
-------- -------- --------
Net cash used in investing activities (33,171) (37,313) (19,722)
-------- -------- --------
Financing Activities
Issuance of long-term debt 2,500 43,000 -
Sale of common stock 3,988 8,325 7,988
Short-term debt, net 10,155 (744) 2,100
Retirement of preferred stock (7,070) - -
Retirement of long-term debt (5,382) (34,216) (18,844)
Common and preferred dividends paid (18,845) (18,112) (18,174)
Repurchase of common stock (735) - -
Other - 336 (180)
-------- -------- --------
Net cash used by financing activities (15,389) (1,411) (27,110)
-------- -------- --------
Net Increase (Decrease) In Cash 850 (1,891) 2,072
Cash at Beginning of Year 823 2,714 642
-------- -------- --------
Cash at End of Year $ 1,673 $ 823 $ 2,714
======== ======== ========
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized) $ 9,673 $ 9,991 $ 12,565
Income taxes (net of refunds) $ 4,687 $ 5,337 $ 6,571
Non-cash Investing and Financing Activities
Regulatory assets (Notes 2 and 11)
Long-term lease arrangements (Note 13)
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEET
(Dollars in thousands)
December 31
1994 1993
Assets
Utility Plant, at original cost $434,059 $421,929
Less accumulated depreciation 125,800 112,299
-------- --------
308,259 309,630
Construction work in progress 15,099 8,388
Nuclear fuel, net 1,197 1,390
-------- --------
Net utility plant 324,555 319,408
-------- --------
Investments and Other Assets
Investments in affiliates, at equity 26,765 26,963
Non-utility investments 28,184 30,123
Non-utility property, less accumulated depreciation 2,989 3,203
-------- --------
Total investments and other assets 57,938 60,289
-------- --------
Current Assets
Cash 1,673 823
Temporary investments, at market value 5,886 1,162
Accounts receivable 20,523 18,614
Unbilled revenues 10,696 10,959
Materials and supplies, at average cost 4,182 4,641
Prepayments 3,544 3,098
Other current assets 4,806 4,821
-------- --------
Total current assets 51,310 44,118
-------- --------
Regulatory Assets and Other Deferred Charges 56,596 56,335
-------- --------
Total Assets $490,399 $480,150
======== ========
The accompanying notes are an integral part of these consolidated financial statements.
December 31
Capitalization And Liabilities 1994 1993
Capitalization
Common stock equity $170,784 $173,836
Preferred and preference stock 8,054 15,054
Preferred stock with sinking fund requirements 20,000 20,000
Long-term debt 120,157 122,419
-------- --------
Total capitalization 318,995 331,309
-------- --------
Long-term Lease Arrangements 20,467 21,553
-------- --------
Current Liabilities
Short-term debt 11,511 1,356
Current portion of long-term debt 4,230 4,850
Accounts payable 5,970 7,002
Accounts payable - affiliates 8,435 7,488
Accrued interest 671 564
Accrued income taxes 3,997 788
Dividends declared 2,853 664
Other current liabilities 26,002 23,913
-------- --------
Total current liabilities 63,669 46,625
-------- --------
Deferred Credits
Deferred income taxes 52,710 52,028
Deferred investment tax credits 8,394 8,785
Yankee Atomic purchased power contract 10,725 9,768
Environmental cleanup 5,050 4,900
Other deferred credits 10,389 5,182
-------- --------
Total deferred credits 87,268 80,663
-------- --------
Commitments and Contingencies
Total Capitalization and Liabilities $490,399 $480,150
======== ========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CAPITALIZATION
(Dollars in thousands)
December 31
1994 1993
Common Stock Equity
Common stock, $6 par value, authorized
19,000,000 shares; outstanding 11,785,848
shares in 1994 and 11,562,219 shares in
1993 $ 70,715 $ 69,373
Other paid-in capital 45,229 42,584
Treasury stock (56,400 shares at cost) (735) -
Retained earnings 55,575 61,879
-------- --------
Total common stock equity 170,784 173,836
-------- --------
Cumulative Preferred and Preference Stock
Preferred stock, $100 par value, authorized
500,000 shares
Outstanding:
Non-redeemable
4.15 % Series; 37,856 shares 3,786 3,786
4.65 % Series; 10,000 shares 1,000 1,000
4.75 % Series; 17,682 shares 1,768 1,768
5.375% Series; 15,000 shares 1,500 1,500
Redeemable
8.30 % Series; 200,000 shares 20,000 20,000
Preferred stock, $25 par value, authorized
1,000,000 shares
Outstanding - none - 7,000
Preference stock, $1 par value, authorized
1,000,000 shares
Outstanding - none - -
-------- --------
Total cumulative preferred and preference stock 28,054 35,054
-------- --------
Long-Term Debt
First Mortgage Bonds
5 1/8% Series M , due 1995 4,230 4,255
6 3/4% Series N , due 1996 - 4,325
9 1/2% Series Y , due 2003 - 1,000
9.20 % Series EE, due 1998 7,500 7,500
9.20 % Series FF, due 2000 7,500 7,500
9.26 % Series GG, due 2002 3,000 3,000
9.97 % Series HH, due 2003 25,000 25,000
8.91 % Series JJ, due 2031 15,000 15,000
5.30 % Series KK, due 1998 10,000 10,000
5.54 % Series LL, due 2000 5,000 5,000
6.01 % Series MM, due 2003 7,500 7,500
6.27 % Series NN, due 2008 3,000 3,000
6.90 % Series OO, due 2023 17,500 17,500
Vermont Industrial Development Authority Bonds
Variable, due 2013 (4.25% at December 31, 1994) 5,800 5,800
New Hampshire Industrial Development Authority Bonds
6 7/8%, due 2009 5,500 5,500
Connecticut Development Authority Bonds
Variable, due 2015 (3.5% at December 31, 1994) 5,000 5,000
Other, various 2,857 389
-------- --------
124,387 127,269
Less current portion 4,230 4,850
-------- --------
Total long-term debt 120,157 122,419
-------- --------
Total Capitalization $318,995 $331,309
======== ========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCK EQUITY
(Dollars in thousands)
Other
Common Stock Paid-in Treasury Retained
Shares Amount Capital Stock Earnings Total
Balance, December 31, 1991 10,808,463 $64,851 $30,993 $ - $ 55,836 $151,680
Sale of common stock 388,113 2,329 5,659 7,988
Net income 21,422 21,422
Cash dividends on capital stock:
Common stock - $1.39 per share (19,162) (19,162)
Cumulative preferred stock:
Non-redeemable (998) (998)
Redeemable (1,660) (1,660)
Common and preferred stock
issuance expenses (180) (180)
---------- ------- ------- ----- -------- --------
Balance, December 31, 1992 11,196,576 67,180 36,472 - 55,438 159,090
Sale of common stock 365,643 2,193 6,132 8,325
Net income 21,292 21,292
Cash dividends on capital stock:
Common stock - $1.42 per share (12,193) (12,193)
Cumulative preferred stock:
Non-redeemable (998) (998)
Redeemable (1,660) (1,660)
Common and preferred stock
issuance expenses (20) (20)
---------- ------- -------- ----- -------- --------
Balance, December 31, 1993 11,562,219 69,373 42,584 - 61,879 173,836
Sale of common stock 223,629 1,342 2,646 3,988
Treasury stock at cost (56,400) (735) (735)
Net income 14,800 14,800
Cash dividends on capital stock:
Common stock - $1.42 per share (16,620) (16,620)
Common stock - $.20 per share (2,346) (2,346)
Cumulative preferred stock:
Non-redeemable (408) (408)
Redeemable (1,660) (1,660)
Premium (70) (70)
Common stock issuance expenses (1) (1)
---------- ------- ------- ----- -------- --------
Balance, December 31, 1994 11,729,448 $70,715 $45,229 $(735) $ 55,575 $170,784
---------- ------- ------- ----- -------- --------
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1
Summary of significant accounting policies
Consolidation The consolidated financial statements include the accounts of
the Company and its wholly owned subsidiaries.
Regulation The Company is subject to regulation by the Vermont Public Service
Board (PSB), the Federal Energy Regulatory Commission (FERC) and, to a lesser
extent, the public utilities commissions in other New England states where the
Company does business, with respect to rates charged for service, accounting
and other matters pertaining to regulated operations. As such, the Company
currently prepares its financial statements in accordance with Statement of
Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of
Certain Types of Regulation, and records various regulatory assets and
liabilities. In order for a company to report under SFAS No. 71, the
Company's rates must be designed to recover its costs of providing service,
and the Company must be able to collect those rates from customers. If rate
recovery of these costs becomes unlikely or uncertain, whether due to
competition or regulatory action, these accounting standards may no longer
apply to the Company's regulated operations. Management believes that the
Company currently meets the criteria for continued application of SFAS No. 71,
but will continue to evaluate significant changes in the regulatory and
competitive environment to assess the Company's overall consistency with the
criteria of SFAS No. 71. In the event the Company determines that it no
longer meets the criteria for applying SFAS No. 71, the accounting impact
would be an extraordinary non-cash charge to operations of an amount that
could be material.
Revenues Estimated unbilled revenues are recorded at the end of accounting
periods. Unbilled revenues of approximately $18.6 million, $18.3 million and
$18.5 million for 1992, 1993 and 1994, respectively, are included in revenues
on the Consolidated Statement of Income.
Maintenance Maintenance and repairs, including replacements not qualifying as
retirement units of property, are charged to maintenance expense.
Replacements of retirement units are charged to utility plant. The original
cost of units retired plus the cost of removal, less salvage, is charged to
the accumulated provision for depreciation.
Depreciation The Company uses the straight-line remaining life method of
depreciation. Total depreciation expense was approximately 3.5% of the cost
of depreciable utility plant for each of the years 1992 through 1994.
Income Taxes The Company records income taxes in accordance with SFAS No. 109,
Accounting for Income Taxes, which requires an asset and liability approach
to determine income tax liabilities. The standard recognizes tax assets and
liabilities for the cumulative effect of all temporary differences between
financial statement carrying amounts and the tax basis of assets and
liabilities, see Note 11. The deferred method under Accounting Principle
Board's Opinion 11, was applied in 1992. Deferred income taxes were provided
to recognize the income tax effect of reporting certain transactions in
different years for income tax and financial reporting purposes. Investment
tax credits associated with utility plant are deferred and amortized ratably
to income over the lives of the related properties. Investment tax credits
associated with non-utility plant are recognized as income in the year
realized.
Allowance for Funds During Construction Allowance for funds used during
construction (AFDC) is the cost, during the period of construction, of debt
and equity funds used to finance construction projects. The Company
capitalizes AFDC as a part of the cost of major utility plant projects to the
extent that costs applicable to such construction work in progress have not
been included in rate base in connection with rate-making proceedings. AFDC
equity represents a current non-cash credit to earnings which is recovered
over the life of the property. The AFDC rates used by the Company were
10.51%, 5.09% and 8.05% for the years 1992 through 1994, respectively.
Regulatory Assets and Other Deferred Charges Certain costs are deferred and
amortized in accordance with authorized or expected rate-making treatment.
The major components of these costs are $19.2 million for Conservation and
Load Management, $12.4 million for Yankee Atomic Electric Company dismantling
costs, $10.6 million for SFAS No. 109, and $4.8 million of restructuring
costs. During regular nuclear refueling outages, the increased costs
attributable to replacement energy purchased from NEPOOL and maintenance costs
are deferred and amortized ratably to expense until the next regularly
scheduled refueling shutdown. The Company earns a return on the unamortized
replacement energy and maintenance costs. See Note 2 to the Consolidated
Financial Statements for discussion of the costs associated with the
discontinued operation of the Yankee Atomic Nuclear Power Corporation nuclear
power plant.
Purchased Power The Company records the annual cost of power obtained under
long-term contracts as operating expenses. Since these contracts, as more
fully described in Note 13, do not convey to the Company the right to use
property, plant, or equipment, they are considered executory in nature. This
accounting treatment is in contrast to the Company's commitment with respect
to the Hydro Quebec Phase I and II transmission facilities which are
considered capital leases. As such, the Company has recorded a liability for
its commitment under the Phase I and II arrangements and recognized an asset
for the right to use these facilities.
Note 2
Investments in affiliates
The Company uses the equity method to account for its investments in the
following companies (dollars in thousands):
December 31
Ownership 1994 1993
Nuclear generating companies:
Vermont Yankee Nuclear Power Corporation 31.3% $16,916 $16,811
Connecticut Yankee Atomic Power Company 2.0% 2,011 2,016
Maine Yankee Atomic Power Company 2.0% 1,338 1,349
Yankee Atomic Electric Company 3.5% 813 836
------- -------
21,078 21,012
Vermont Electric Power Company, Inc.:
Common stock 56.8% 3,494 3,498
Preferred stock 2,193 2,453
------- -------
$26,765 $26,963
======= =======
Each sponsor of the nuclear generating companies is obligated to pay an
amount equal to its entitlement percentage of fuel, operating expenses
(including decommissioning expenses) and cost of capital and is entitled to a
similar share of the power output of the plants. The Company's entitlement
percentages are identical to the ownership percentages except that Vermont
Yankee's entitlement percentage is 35%. The Company is obligated to
contribute its entitlement percentage of the capital requirements of Vermont
Yankee and Maine Yankee and has a similar, but limited, obligation to
Connecticut Yankee. The Company is responsible for paying its entitlement
percentage of decommissioning costs for Vermont Yankee, Connecticut Yankee,
Maine Yankee and Yankee Atomic as follows (dollars in millions):
CVPS's
Total Share of
Date of Estimated CVPS's Funded
Study Obligation Obligation Obligation
Nuclear generating companies:
Vermont Yankee 1993 $312.7 $109.4 $40.3
Maine Yankee 1993 $316.6 $6.3 $2.2
Connecticut Yankee 1992 $294.2 $5.9 $3.0
Yankee Atomic 1994 $370 $13.0 $3.6
On February 26, 1992, the Board of Directors of Yankee Atomic decided to
permanently discontinue operation of their plant, and to decommission the
facility.
The Company relied on Yankee Atomic for less than 1.5% of its system
capacity. Presently, purchased power costs billed to the Company by Yankee
Atomic, which include a provision for ultimate decommissioning of the unit,
are being collected from the Company's customers via existing retail rate
tariffs.
On March 18, 1993, the FERC approved a settlement agreement regarding the
decommissioning plan, recovery of plant investment and all issues with respect
to prudency of the decision to discontinue operation which included
$247 million of decommissioning costs in 1992 dollars. Based on a new study
developed by Yankee Atomic, decommissioning costs are approximately $370
million in 1994 dollars. The increase results primarily from delays in
finding a permanent repository for its spent nuclear fuel. The new study is
subject to FERC approval. Yankee Atomic is currently collecting from sponsors
decommissioning costs based on $247 million in 1992 dollars and anticipates
to begin collecting from sponsors based on $370 million in November 1995.
The Company's share of the increase in decommissioning costs is approximately
$4.3 million.
The Company's total current share of its cost with respect to Yankee
Atomic's decision to discontinue operation is approximately $12.4 million.
This amount is reflected in the accompanying balance sheet both as a
regulatory asset and deferred power contract obligation (current and non-
current).
The Company believes that its proportionate share of Yankee Atomic costs
will be recovered through the regulatory process and, therefore, the ultimate
resolution of the premature retirement of the 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 or license lives.
The Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $8.9 billion. Beyond that a licensee
maintains an indemnity agreement with the Nuclear Regulatory Commission, but
subject to Congressional approval. The first $200 million of liability
coverage is the maximum provided by private insurance. The Secondary
Financial Protection Program is a retrospective insurance plan providing
additional coverage up to $8.7 billion per incident by assessing $79.3 million
against each of the 110 reactor units that are currently subject to the
Program in the United States, limited to a maximum assessment of $10 million
per incident per nuclear unit in any one year. The maximum assessment is to
be adjusted at least every five years to reflect inflationary changes. The
Company's interests in the nuclear power units are such that it could become
liable for an aggregate of approximately $4.4 million of such maximum
assessment per incident per year.
Summarized financial information for Vermont Yankee Nuclear Power
Corporation is as follows (dollars in thousands):
Earnings 1994 1993 1992
Operating revenues $162,757 $180,145 $175,919
Operating income $14,355 $16,441 $16,304
Net income $6,588 $7,794 $7,921
Company's equity in net income $2,067 $2,434 $2,476
December 31
Investment 1994 1993
Current assets $ 41,416 $ 40,136
Non-current assets 470,726 429,634
-------- --------
Total assets 512,142 469,770
Less:
Current liabilities 37,287 32,021
Non-current liabilities 420,382 383,585
-------- --------
Net assets $ 54,473 $ 54,164
-------- --------
Company's equity in net assets $ 16,916 $ 16,811
Included in Vermont Yankee's revenues shown above are sales to the
Company of $52.9 million, $52.3 million and $53.6 million for 1992 through
1994, respectively. These amounts are reflected as purchased power net of
deferrals and amortization in the accompanying Consolidated Statement of
Income.
Vermont Electric Power Company, Inc. (Velco) and its wholly owned
subsidiary Vermont Electric Transmission Company, Inc. (Vetco) own and operate
transmission systems in Vermont over which bulk power is delivered to all
electric utilities in the state. Velco has entered into transmission
agreements with the state of Vermont and the electric utilities and under
these agreements bills all costs, including interest on debt and a fixed
return on equity, to the state and others using the system. These contracts
enable Velco to finance its facilities primarily through the sale of first
mortgage bonds. Included in Velco's revenues shown below are transmission
services to the Company (reflected as production and transmission in the
accompanying Consolidated Statement of Income) amounting to $8.3 million,
$8.9 million and $8.4 million for 1992 through 1994, respectively.
Velco operates pursuant to the terms of the 1985 Four-Party Agreement (as
amended) with the Company and two other major distribution companies in
Vermont. Although the Company owns 56.8% of Velco's outstanding common stock,
the Four-Party Agreement effectively restricts the Company's control of Velco.
Therefore, Velco's financial statements have not been consolidated. The Four-
Party Agreement continues in full force and effect until May 1995 and will be
extended for an additional two-year term in May 1995, and every two years
thereafter, unless at least ninety (90) days prior to any two-year anniversary
any party shall notify the other parties in writing that it desires to
terminate the agreement as of such anniversary. No such notification has been
filed by the parties. The Company also owns 46.6% of Velco's outstanding
preferred stock, $100 par value.
Summarized financial information for Velco is as follows (dollars in
thousands):
Earnings 1994 1993 1992
Transmission revenues $16,761 $17,891 $16,722
Operating income $3,350 $4,423 $4,379
Net income $1,296 $1,375 $1,494
Company's equity in net income $638 $698 $749
December 31
Investment 1994 1993
Current assets $16,549 $15,181
Non-current assets 53,175 55,018
------- -------
Total assets 69,724 70,199
Less:
Current liabilities 15,941 13,180
Non-current liabilities 42,909 45,626
------- -------
Net assets $10,874 $11,393
======= =======
Company's equity in net assets $ 5,687 $ 5,951
Note 3
Non-utility investments
The Company's wholly owned subsidiary, Catamount Energy Corporation
(Catamount) invests through its wholly owned subsidiaries in non-regulated,
energy-related projects. Certain financial information for Catamount's
investments is set forth in the table that follows (dollars in thousands):
Investment
Generating December 31
Projects Location Capacity Fuel Ownership 1994 1993
Rumford Cogeneration Co. (Rumford) Maine 85MW Coal/Wood 15.1% $9,804 $6,280
Ryegate Associates (Equinox) Vermont 20MW Wood 33.1% $6,587 $7,034
Appomattox Cogeneration (Appomattox) Virginia 57MW Wood/Coal 50.0% $9,819 $10,668
Black liquor
NW Energy Williams Lake L.P. British Columbia, 60MW Wood 8.1% $1,550 $1,975
(Williams Lake) Canada
The Rumford project was placed in service on August 1, 1990. The Ryegate
and Williams Lake projects began commercial operation on November 1, 1992 and
April 2, 1993, respectively. On October 26, 1992, Appomattox purchased a 50%
partnership interest in Appomattox Cogeneration which owns a power sales
agreement associated with a cogeneration facility currently in operation.
In January 1994, Catamount purchased an additional 4.185% limited
partnership interest in Rumford Cogeneration Co. This additional investment
increased Rumford's ownership in the project to 15.1%.
SmartEnergy Services, Inc. (SmartEnergy) also is a wholly owned
subsidiary of the Company, whose purpose is to cost effectively provide
reliable, energy efficient products and services, including the rental of
electric water heaters. Prior to January 1, 1993, the rental electric water
heater program was part of the Company's core electric business and reported
as non-operating income.
On October 1, 1993, SmartEnergy purchased for $1.2 million, 304,125
shares (5%) of Green Technologies, Inc. (Green Technologies) common stock and
on September 19, 1994, purchased for $540,000, an additional 120,000 shares
(1.8%). This investment increased SmartEnergy's ownership in Green
Technologies to 6.8%. Green Technologies of Boulder, Colorado, currently
manufactures Green Plug electricity savers for several types of household
appliances. SmartEnergy uses the cost method of accounting for its investment
in Green Technologies. During the fourth quarter of 1994, SmartEnergy wrote-
down its investment in Green Technologies by approximately $1.3 million to
reflect management's estimate of the permanent decline in value of the
investment. SmartEnergy's investment in Green Technologies was approximately
$.42 million and $1.2 million at December 31, 1994 and 1993, respectively.
Note 4
Redeemable preferred stock
Commencing in 1998, the 8.30% Dividend Series Preferred Stock is
redeemable at par through a mandatory sinking fund in the amount of $1.0
million per annum, and at its option, the Company may redeem at par an
additional non-cumulative $1.0 million per annum.
Note 5
Common Stock
On November 8, 1994, the Company's board of directors (Board) announced a
new dividend policy that targeted future dividends at 60% of earnings. In
light of the new policy, the current annual dividend of $1.42 was reduced 44%
to $.80 effective with the first quarter dividend paid in February 1995.
Accordingly, on December 5, 1994, the Board declared a quarterly common stock
dividend of $.20 per share payable February 15, 1995 to shareholders of record
on January 31, 1995. The dividend payment level will be reviewed regularly in
light of capital needs, projected earnings levels and other relevant factors.
Also, the Board authorized the purchase of up to 2 million shares of its
outstanding common stock in open market transactions. As of December 31,
1994, the Company had purchased 56,400 shares at an average price of $12.98
per share. These transactions are recorded as treasury stock, at cost, in the
Company's Consolidated Balance Sheet.
As of February 8, 1995, the Company had purchased 74,700 shares at an
average price of $12.99 per share.
Note 6
Long-term debt and sinking fund requirements
Based on issues outstanding at December 31, 1994, the aggregate amount of
long-term debt maturities and sinking fund requirements (exclusive of the
amount that may be satisfied by property additions) are approximately
$4.2 million, $1.0 million, $3.0 million, $20.5 million and $5.5 million for
the years 1995 through 1999, respectively. Substantially all property and
plant is subject to liens under the First Mortgage Bonds.
Note 7
Financial instruments
The estimated fair values of the Company's financial instruments at
December 31, 1994 are as follows (dollars in thousands):
Carrying Fair
Amount Value
Cash and temporary cash investments $ 7,559 $ 7,559
Short-term debt $ 11,511 $ 11,511
Investments $ 424 $ 424
Sale of accounts receivable and
unbilled revenues $ 12,000 $ 12,000
Redeemable preferred stock $ 20,000 $ 18,790
Long-term debt $124,387 $119,374
The carrying amount for cash, temporary cash investments and short-term
debt approximates fair value because of the short maturity of those
instruments.
The carrying amount and the fair value of the Company's investment in
Green Technologies, Inc. reflects management's estimate of the realizable
value of the investment.
The carrying amount for the sale of accounts receivable and unbilled
revenues approximates fair value because of the short maturity of those
instruments.
The fair value of the Company's redeemable preferred stock and long-term
debt is estimated based on the quoted market prices for the same or similar
issues or on the current rates offered to the Company for debt of the same
remaining maturation.
Anticipated regulatory treatment of any excess or decline in the fair
value relative to the carrying value of the Company's financial instruments,
if they were settled at amounts approximating those above, would result in an
increase or decrease in the Company's rates over a prescribed amortization
period. Accordingly, any settlement would not result in a material impact on
the Company's financial position or results of operations.
The Company has no financial instruments that fall under the guidance of
SFAS No. 119, Disclosure about Derivative Financial Instruments and Fair Value
of Financial Instruments.
In May 1993, the FASB issued SFAS No. 115, Accounting for Certain
Investments in Debt and Equity Securities, effective for fiscal years
beginning after December 15, 1993. SFAS No. 115 addresses the accounting and
reporting for investments in equity securities that have readily determinable
fair values and for all investments in debt securities. The Company has the
following investments that are covered by the principles of SFAS No. 115:
temporary cash investments classified as trading activities and reported at
market value, and its available for sale investment in Green Technologies,
Inc. For additional information, see Note 3 herein. The adoption of SFAS
No. 115 had no material impact on the Company's financial position or results
of operations.
Note 8
Accounts receivable
In 1988 the Company entered into an agreement to sell up to $20 million
of certain accounts receivable and unbilled revenues. At December 31, 1994
and 1993, a total of $12 million of accounts receivable and unbilled revenues
were sold under an accounts receivable facility.
Accounts receivable and unbilled revenues that have been sold were
transferred with limited recourse. A pool of assets, varying between 3% to 5%
of the accounts receivable and unbilled revenues sold, are set aside for this
potential recourse liability. Accounts receivable and unbilled revenues are
reflected net of sales of $4.2 million and $7.8 million, respectively, at
December 31, 1994 and $4.7 million and $7.3 million, respectively, at
December 31, 1993.
Accounts receivable are also reflected net of an allowance for
uncollectible accounts of $1.0 million and $.9 million at December 31, 1994
and 1993, respectively.
Note 9
Short-term debt
Utility
The Company uses committed lines of credit and uncommitted loan
facilities to finance its construction and C&LM programs, on a short-term
basis, and for other corporate purposes. As of December 31, 1994, the Company
had $18.25 million of committed lines of credit and $25 million of uncommitted
loan facilities which are normally renewed upon expiration and require annual
fees ranging from zero to .25% of an individual line. Borrowings under these
short-term debt arrangements are at interest rates ranging from less than
prime to the prime rate. The Company had $11.5 million and $1.4 million of
outstanding short-term debt at December 31, 1994 and 1993, respectively, at
average interest rates of 5.22% for 1994 and 3.61% for 1993.
Non-Utility
Catamount maintains an Irrevocable Standby Letter of Credit with a bank
to borrow up to an aggregate amount of $2.3 million to replace its share of
cash in the Appomattox Cogeneration Limited Partnership's Project Debt Service
Reserve Fund. This Letter of Credit is for a one-year term with annual
extensions available and requires fees totaling 2.527% of credit available.
At December 31, 1994 and 1993, there were no borrowings outstanding under this
Letter of Credit. Catamount believes it will not have to perform under this
agreement because the likelihood of default by the primary party is remote.
SmartEnergy maintains a $1.0 million revolving line of credit with a bank
to provide working capital and financing assistance for investment purposes.
SmartEnergy had $846,000 and $696,000 of outstanding short-term debt at
December 31, 1994 and 1993, respectively, at average interest rates of 7.29%
for 1994 and 6.08% for 1993.
Financial obligations of the non-utility wholly owned subsidiaries are
non-recourse to the Company.
Note 10
Pension and postretirement benefits
The Company has a non-contributory trusteed pension plan covering all
employees (union and non-union). Under the terms of the pension plan,
employees are generally eligible for monthly benefit payments upon reaching
the age of 65 with a minimum of five years of service. The Company's funding
policy is to contribute, at least, the statutory minimum to a trust. The
Company is not required by its union contract to contribute to multi-employer
plans.
The projected unit credit actuarial cost method was used to compute net
pension costs and the accumulated and projected benefit obligations. The
change in the accumulated benefit obligation and projected benefit obligation
for 1993 and 1994 results primarily from changes in plan assumptions. The
following table sets forth the funded status of the pension plan and amounts
recognized in the Company's Balance Sheet and Statement of Income (dollars in
thousands):
December 31
1994 1993 1992
Funded status of the plan
Vested benefit obligation $35,869 $35,837 $27,899
Non-vested benefit obligation 312 493 439
------- ------- -------
Accumulated benefit obligation $36,181 $36,330 $28,338
------- ------- -------
Projected benefit obligation $46,669 $49,743 $39,001
Market value of plan assets (primarily equity
and fixed income securities) 44,115 46,074 39,768
------- ------- -------
Projected benefit obligation more (less)
than market value of plan assets 2,554 3,669 (767)
Unrecognized net transition assets 1,608 1,768 1,929
Unrecognized prior service costs (3,178) (3,568) (3,084)
Unrecognized net gain 5,963 1,498 5,314
------- ------- -------
Net pension liability 6,947 3,367 3,392
Less regulatory asset for restructuring costs 1,974 - -
------- ------- -------
Effective accrued pension costs $ 4,973 $ 3,367 $ 3,392
------- ------- -------
Net pension costs include the following components
Service cost $ 2,065 $ 1,491 $ 1,307
Interest cost 3,694 3,377 3,065
Actual return on plan assets 515 (6,800) (4,137)
Net amortization and deferral (4,095) 3,391 890
------- ------- -------
Pension costs 2,179 1,459 1,125
Amortization of regulatory asset 261 - -
------- ------- -------
Effective pension costs 2,440 1,459 1,125
Less amount allocated to other accounts 318 276 223
------- ------- -------
Net pension costs expensed $ 2,122 $ 1,183 $ 902
------- ------- -------
Assumptions used in calculating pension cost were as follows:
December 31
1994 1993 1992
Weighted average discount rates 8.50% 7.25% 8.50%
Expected long-term return on assets 9.50% 9.75% 10.25%
Rate of increase in future compensation levels 5.00% 4.75% 5.50%
The Company sponsors a defined benefit postretirement medical plan that
covers all employees who retire with ten years or more of service after age
45.
Effective January 1, 1993, the Company adopted, on a prospective basis,
SFAS No. 106, Employer's Accounting for Postretirement Benefits Other Than
Pensions (OPEB) which requires accrual of the expected costs of such benefits
during the employees' years of service. In 1994, the Company adopted a policy
to fund its OPEB obligation through a Voluntary Employees' Benefit Association
and 401(h) Subaccount in its Pension Plan.
The following table sets forth the plan's funded status and amounts
recognized in the Company's Balance Sheet and the amount of expense charged to
the Company's Statement of Income in accordance with SFAS No. 106 (dollars in
thousands):
December 31
1994 1993
Accumulated postretirement benefit obligation
Retirees $(8,265) $(5,098)
Fully eligible active plan participants (521) (1,207)
Other active plan participants (806) (1,293)
Plan assets at fair value 744 -
------- -------
Accumulated postretirement benefit obligation
in excess of plan assets (8,848) (7,598)
Unrecognized transition obligation 5,485 6,253
Unrecognized net loss 337 351
------- -------
Accrued postretirement benefit cost (3,026) (994)
Regulatory asset for restructuring costs 2,008 -
------- -------
Effective accrued postretirement benefit costs $(1,018) $ (994)
======= =======
Net postretirement benefit cost includes the
following components
Service cost $ 194 $ 168
Interest cost 682 588
Actual return on plan assets 1 -
Deferral of asset gain during the year (1) -
Amortization of transition obligation over
a twenty-year period 305 329
------- -------
Postretirement benefit cost 1,181 1,085
Amortization of regulatory asset 265 -
------- -------
Effective postretirement benefit cost 1,446 1,085
Less amount allocated to other accounts 172 205
------- -------
Net postretirement benefit cost expensed $ 1,274 $ 880
======= =======
Assumptions used in the per capita costs of the accumulated postretire-
ment benefit obligation were as follows:
December 31
1994 1993
Per capita percent increase in health care costs:
Pre-65 9.50% 9.50%
Post-65 8.00% 6.00%
Weighted average discount rates 8.50% 7.25%
Rate of increase in future compensation levels 5.00% 4.75%
Health care trend rates are assumed to decrease to 6.0% for pre-65 and
5.5% for post-65 for the year 2001 and thereafter.
This decrease results from changes to the retiree medical plan limiting
the cost for employees retiring after 1995 to the 1995 per participant cost.
Increasing the assumed health care cost trend rates by one percentage point in
each year would have resulted in an increase of approximately $709,000 in the
accumulated postretirement benefit obligation as of January 1, 1995, and an
increase of about $57,000 in the aggregate of the service cost and interest
cost components of net periodic postretirement benefit cost for 1994. Prior
to 1993, the Company expensed OPEB's costs as benefits were paid. Such costs
totaled $546,000 for 1992.
Effective January 1, 1994, the Company adopted, on a prospective basis,
SFAS No. 112, Employers' Accounting for Postemployment Benefits which requires
accrual of the expected cost of postemployment benefits provided to former or
inactive employees, their beneficiaries, and covered dependents after
employment but before retirement. The Company provides postemployment
benefits consisting of long-term disability benefits, and prior to January 1,
1994 expensed these costs as benefits were paid. Such costs total $91,000 and
$156,000 for 1992 and 1993, respectively. The accumulated postemployment
benefit obligation at January 1, 1995 of approximately $1.3 million is
reflected in the accompanying balance sheet as a deferred postemployment
benefit obligation (current and non-current) and is offset by a corresponding
regulatory asset of approximately $1.0 million. The PSB in its October 31,
1994 Rate Order allowed the Company to recover the regulatory asset over a
7-1/2 year period beginning November 1, 1994 through April 30, 2002. The
postemployment benefit cost charged to expense in 1994 was approximately
$324,000 (pre-tax).
In the first quarter of 1994, the Company offered and recorded an
obligation related to a Voluntary Retirement Program (VRP). The VRP was
accepted by 42 employees. The estimated benefit obligation for the VRP as of
December 31, 1994 is about $4.5 million. This amount consists of pension
benefits and postretirement medical benefits of $2.2 million and $2.3 million,
respectively. Additionally, 32 employees accepted a Voluntary Severance
Program (VSP) offered by the Company. Eligible employees had until April 22,
1994 to apply. The Company also announced a layoff of 20 employees on May 9,
1994. VSP and layoff obligations of $.8 million and $.2 million,
respectively, were recorded in the second quarter of 1994. At December 31,
1994, the benefit obligation for the VSP was about $96,000. The VRP, VSP and
layoff combined with attrition since mid-1993, yields a total work force
reduction of approximately 14%. In the October 31, 1994 PSB Rate Order, the
Company was allowed rate recovery of this restructuring cost over a five-year
period. The unamortized balance of these costs was approximately $4.8 million
at December 31, 1994.
Note 11
Income taxes
The components of Federal and state income tax expense are as follows
(dollars in thousands):
Year Ended December 31
1994 1993 1992
Federal:
Current $ 6,177 $ 2,751 $ 7,774
Deferred 3,417 7,893 2,042
Investment tax credits, net (391) (391) (391)
------- ------- -------
9,203 10,253 9,425
------- ------- -------
State:
Current 1,710 406 1,987
Deferred 496 2,113 1,001
------- ------- -------
2,206 2,519 2,988
------- ------- -------
Total Federal and state income taxes $11,409 $12,772 $12,413
======= ======= =======
Federal and state income taxes charged (credited) to:
Operating expenses $11,934 $12,496 $12,102
Other income (525) 276 311
------- ------- -------
$11,409 $12,772 $12,413
======= ======= =======
The principal components of deferred income tax expense for 1992 were
additional depreciation for tax purposes of $3.9 million offset by $.9 million
of contributions in aid of construction.
The principal items comprising the difference between the total income
tax expense and the amount calculated by applying the statutory Federal income
tax rate to income before tax are as follows (dollars in thousands):
Year Ended December 31
1994 1993 1992
Income before income tax $26,209 $34,064 $33,835
Federal statutory rate 35% 35% 34%
Federal statutory tax expense $ 9,173 $11,922 $11,504
Increases (reductions) in taxes resulting
from:
Disallowed regulatory tax asset 1,641 - -
Dividend received deduction (854) (995) (353)
Deferred taxes on plant previously
"flowed-through" 523 523 523
State income taxes net of Federal tax
benefit 1,434 1,637 1,707
Investment credit amortization (391) (391) (391)
Seabrook project 76 139 70
Book-to-return adjustments and other (193) (63) (647)
------- ------- -------
Total income tax expense provided $11,409 $12,772 $12,413
======= ======= =======
The tax effects of temporary differences and tax carry forward that give
rise to significant portions of the deferred tax assets and deferred tax
liabilities are presented below (dollars in thousands):
Year Ended December 31
1994 1993
Deferred tax assets
Alternative minimum tax credit carry
forward $ 900 $ 1,400
Non-deductible accruals and othe 4,682 4,186
Deferred compensation and pension 4,651 4,058
Environmental costs accrual 2,335 2,142
------- -------
Total deferred tax assets 12,568 11,786
------- -------
Deferred tax liabilities
Property, plant and equipment 41,609 38,304
Net regulatory asset 12,217 13,806
Conservation and load management
expenditures 7,664 5,123
Nuclear refueling costs 473 2,633
Other 3,315 3,948
------- -------
Total deferred tax liabilities 65,278 63,814
------- -------
Net deferred tax liability $52,710 $52,028
======= =======
As a result of adopting SFAS No. 109 in 1993, the Company recognized
additional net accumulated deferred income tax liabilities of approximately
$15 million and a net corresponding regulatory asset from customers of
approximately $15 million for future revenues that will be received when the
temporary differences reverse and are settled in rates. As a result of the
October 31, 1994 PSB Rate Order, during the fourth quarter of 1994, the
Company recognized an additional $1.6 million of tax expense related primarily
to a previous revenue agent review which were expected to be collected from
customers through rates.
A valuation allowance has not been recorded, as the Company expects all
deferred income tax assets will be utilized in the future.
The Company has an alternative minimum tax credit carry forward of
$.9 million which is available to reduce future regular income taxes over an
indefinite period.
Note 12
Retail Rate Increase
A PSB Rate Order dated October 31, 1994, allowed the Company a base
retail rate increase of 4.27% or approximately $8.6 million effective with
service rendered November 1, 1994. On December 14, 1994, the Company received
an amended PSB Rate Order which allowed the Company a base retail rate
increase of 5.07% or approximately $10.2 million. The Company had filed for
an 8.9% or $17.9 million increase in its base retail rates in February 1994.
The PSB Rate Order also lowered the allowed rate of return on the Company's
common stock equity from 12% to 10%. The allowed return on equity is after
deducting a .75% penalty based on the PSB's conclusions that there had been
"mismanagement of power supply options" and because of "the Company's failed
efforts to acquire all cost-effective energy efficiency resources." The
Company disagrees with the PSB's conclusion.
As discussed in Note 11, the Company recorded an additional income tax
provision of $1.6 million which it had previously expected to recover in rates
but was disallowed in the Rate Order.
Note 13
Commitments and contingencies
The Company's power supply is acquired from a variety of sources
including its own generating units, jointly owned units, long-term contracts
and short-term purchases from a variety of sources. Through its investments
in four nuclear generating companies, the Company is entitled to receive power
from those nuclear units. See Note 2 for a discussion of the Company's
obligations related to its investment in nuclear generating companies.
Under long-term contracts with various electric utilities in the region,
the Company is purchasing certain percentages of the electrical output of
production plants constructed and financed by those utilities. Such contracts
obligate the Company to pay certain minimum annual amounts representing the
Company's proportionate share of fixed costs, including debt service
requirements (amounts necessary to retire the principal of and to pay the
interest on the portion of the related long-term debt ascribed to the Company)
whether or not the production plants are operating. The cost of power
obtained under such long-term contracts, including payments required to be
made when a production plant is not operating, is reflected as "Purchased
power" in the Consolidated Statement of Income.
The Company purchases power from a coal-fired generating plant owned by
Northeast Utilities (NU) under a thirty-year contract which expires April 30,
1998. Under this contract the Company is obligated to make capacity payments
which amounted to approximately $3.7 million, $3.8 million and $4.3 million
for 1992 through 1994, respectively. These capacity payments will vary over
the contract period due to factors such as changes in NU's net investment and
allowed rate of return.
The Company purchases power from several small power producers who own
qualifying facilities under the Public Utility Regulatory Policies Act of
1978. These qualifying facilities produce energy using hydroelectric, wood,
biomass, and refuse-burning generation. Under these long-term contracts, in
1994, the Company purchased 34.4 MW of which approximately 30.1 MW is
associated with the Vermont Power Exchange and 3.9 MW with a New
Hampshire/Vermont solid waste plant owned by Wheelabrator Claremont Company,
L.P. The Company expects to purchase approximately 42 MW in each year 1995
through 1999. The total commitment in the next five years to purchase power
from these qualifying facilities is approximately $105.9 million.
The Company will receive varying amounts of capacity and energy from two
Hydro-Quebec contracts during the period 1995-2016. The contract between a
group of Vermont utilities (Vermont Joint Owners) and Hydro-Quebec provides
power over the entire period while a contract between the state of Vermont and
Hydro-Quebec terminates on September 22, 1995. Additional contracts were
negotiated between the Company and Hydro-Quebec which in effect reduce the
amount of power the Company is required to purchase, as well as one signed in
1994 which reduces the cost to the Company.
The maximum net amount of capacity that the Company will purchase during
the term of the agreements is 142.7 MW. The total commitment in the next five
years to purchase power under these contracts is approximately $321 million,
less approximately $112 million of power sellbacks, yielding a net cost of
approximately $209 million.
Early in the Vermont Joint Owners contract, two sellback contracts were
negotiated which reduced the net purchase of Hydro-Quebec power as well as
delayed the purchase of about 24 MW of capacity and associated energy. In
1994, the Company negotiated a third sellback arrangement whereby the Company
receives an effective discount on up to 70 MW of capacity in the 1996 contract
year (declining to 30 MW in the 1999 contract year) in exchange for the right
of Hydro-Quebec to reduce capacity deliveries by up to 50 MW beginning as
early as 2004 until 2015, and the ability to reduce the amounts of energy
delivered in up to five years beginning in 2000.
Joint-ownership The Company's ownership interests in jointly owned generating
and transmission facilities are set forth in the table that follows and
recorded in the Company's Consolidated Balance Sheet (dollars in thousands):
MW December 31
Ownership Entitlement 1994 1993
Generating plants:
Wyman #4 1.78% 11 $ 3,338 $ 3,322
Joseph C. McNeil 20.00% 11 14,871 14,821
Millstone #3 1.73% 20 75,101 75,071
Highgate transmission facility 46.08% 12,775 12,586
-------- --------
106,085 105,800
Accumulated depreciation 25,683 22,535
-------- --------
$ 80,402 $ 83,265
======== ========
Wyman #4, an oil-fired generating plant, commenced commercial operation
in December 1978. The Joseph C. McNeil wood, gas and oil-fired generating
plant commenced commercial operation in June 1984 and the Millstone #3, a
nuclear generating unit, commenced commercial operation in April 1986. The
Highgate transmission interconnection with Canada was placed in service in
September 1985. The Company's share of operating expenses for these
facilities is included in the corresponding operating accounts on the
Consolidated Statement of Income. Each participant in these facilities must
provide for its own financing.
The Company is responsible for paying its ownership percentage of
decommissioning costs for Millstone #3. Based on a 1992 study, total
estimated obligation at December 31, 1994 was approximately $449 million and
the funded obligation was about $76 million. The Company's share for the
total obligation and funded obligation was approximately $7.8 million and
$1.1 million, respectively.
Environmental The Company is engaged in various operations and activities
which subject it to inspection and supervision by both state and Federal
regulatory authorities including the United States Environmental Protection
Agency (EPA) (hereinafter "environmental laws"). It is Company policy to
comply with these environmental laws to the extent currently applicable and
effective against it. The Company has implemented various procedures and
internal controls to assess and assure compliance. If non-compliance is
discovered, corrective action is taken. Based on these efforts and the
oversight of those regulatory agencies having jurisdiction, the Company
believes it conforms, in all material respects, with these environmental laws.
Company operations occasionally result in unavoidable and inadvertent
spills or releases of regulated substances or materials, such as the rupture
of a pole mounted transformer, broken hydraulic line, or other similar
occurrences. When the Company learns of such spills and releases from
ongoing operations, they are cleaned up to meet Federal and state
requirements. Except as discussed in the following paragraphs, the Company is
not aware of any instances where it has caused, permitted or suffered a
release or spill on or about its properties or otherwise which will likely
result in any material environmental liabilities to the Company.
The Company is an amalgamation of more than 100 predecessor companies
engaged in various operations and activities prior to their being incorporated
in the Company. At least two of these companies were involved in the
production of gas from coal to sell and distribute to retail customers at
three different locations. These activities were discontinued by the Company
in the late 1940's or early 1950's. In addition, these predecessor companies
and the Company itself may have historically engaged in other waste disposal
activities, while legal and consistent with commercially accepted practices at
the time, may not meet modern standards and thus represent potential
liability. The Company continues to discover, investigate, evaluate, monitor
and, where appropriate, remediate contaminated sites related to these
historic activities. The Company's policy is to accrue a liability for those
sites where costs for remediation, monitoring and other future activities are
probable and can be reasonably estimated.
Based on these investigations and policies, coal tar deposits were
discovered at the Company's Cleveland Avenue property located in the city of
Rutland, a site where one of its predecessors operated a coal-gasification
facility. Due to the presence of these deposits and uncertainties as to
potential contamination migration off-site, the Company conducted studies to
determine the magnitude and extent of the coal tar releases. The Company
engaged a consultant to assist in evaluating clean-up methodologies and
provide cost estimates. Those studies indicated the cost to remediate the
site would be approximately $5 million. This was charged to expense in the
fourth quarter of 1992. This was followed by an assessment of potential
health, safety and ecological risks. Other site issues are still under
evaluation. A final risk assessment report was completed and submitted to the
state for review. Following state review, various remediation alternatives
will be investigated. The Company was formally contacted by the EPA in
January 1995 asking for written consent to conduct a site evaluation. The
Company does not believe EPA's evaluation changes its potential liability so
long as reasonable further progress is made in remediating the site. The
Company has yet to determine whether insurance proceeds are available to
offset the cost of any remediation required at this site.
The Company is currently investigating its potential liability regarding
three former municipal landfills: the Bennington Landfill, the Parker
Landfill, and the Trafton-Hoisington Landfill. The Bennington Landfill is a
superfund site located in Bennington, Vermont. The Company was contacted in
the winter of 1994 by counsel for a group of potentially responsible parties
(PRP Group) who were performing an engineering evaluation and cost analysis
(EE/CA) for the site under a settlement agreement with the EPA. The PRP Group
threatened contribution litigation against the Company and others to recover
an equitable share of the approximate $3 million the PRP Group had expended
thus far on the EE/CA. Investigation by the Company thus far suggests that it
is unlikely that it contributed a meaningful amount of hazardous substances,
if any, to the site and thus would not be liable for a significant share of
liability for the EE/CA expenses or site clean up. No litigation by the PRP
Group has yet been initiated against the Company.
In July 1994, the EPA notified the Company that it had reviewed evidence
which, in its opinion, indicated that the Company may have contributed to the
environmental contamination at the site but that a full determination of its
potential liability for the site had not been made. EPA, at that time,
designated the Company a potentially interested party (PIP). Also in July
1994, the EPA notified the PRP Group, the Company and other PIPs that it was
proposing a response action at the site with an estimated total present worth
cost of approximately $9.5 million.
During November 1994, the Company was notified that EPA had information
indicating that the Company was a PRP. The EPA letter also requested that the
Company participate with other PRPs in the response action described above and
further made a demand against the Company and other PRPs for reimbursement of
approximately $.85 million in costs EPA had incurred in responding to
conditions at the site.
The PRP Group is attempting to form a larger group of PRPs to undertake
the remedial response, pay EPA response expenses and obtain reimbursement for
the $3 million it spent on the EE/CA. Representatives of the Company have
been in contact with EPA and the PRP Group and have evaluated the merits of
participation with the larger group. The Company is entering into an
agreement to become a part of the larger PRP Group and will also continue to
work with EPA seeking a "de minimis" settlement.
While further investigation is necessary and is continuing, the results
thus far suggest that the Company will defend any contribution action from the
other PRPs and the EPA but will continue to explore settlement options which
appear to be in the overall best interest of the Company. The Company has yet
to determine whether insurance proceeds are available to offset potential
costs for the remediation or other expenses which might be required by the
Company at this site.
The Parker Landfill is a superfund site located in Lyndonville, Vermont.
In 1989, the Company received an information request from the EPA seeking to
determine if the Company sent any hazardous substances to the site. An
investigation conducted at the time concluded general trash was occasionally
sent to the site but the Company had not sent hazardous substances to the
site. In May of 1994, the Company received a second request seeking
additional information regarding disposal practices. A renewed investigation
by the Company again concluded no significant amounts of hazardous substances
were sent to the site. Last summer, EPA also announced its proposed preferred
remedy for this site with an estimated total present net worth cost of
$28.2 million. Final selection of a remedy is anticipated later this year.
Thus far, the Company is considered a PIP, not a PRP, for the site. The
Company has complied with the information request and will monitor EPA
activities at the site.
The Trafton-Hoisington Landfill was a municipal and industrial landfill
in the Town of Windsor, Vermont. The site is presently a state lead site
although placement on the National Priorities List remains a possibility. The
state of Vermont has reached an agreement with a small group of PRPs to
conduct a site investigation. The Company was contacted by these PRPs seeking
contribution toward the cost of the site investigation. The Company conducted
an investigation and concluded no significant amounts of hazardous substances
were sent to the site. The Company has advised the PRPs it will not
voluntarily contribute under these circumstances.
At this time, the Company does not believe these sites represent the
potential for a material adverse effect on its financial condition or results
of operations but will continue to monitor activities at the sites.
The Company is not subject to any pending or threatened litigation with
respect to any other sites where remediation expenses could be material, nor
has the EPA or other state or Federal agency sought contribution from the
Company for the study or remediation of any such sites.
Dividend restrictions The indentures relating to long-term debt and the
Articles of Association contain certain restrictions on the payment of cash
dividends on capital stock. Under the most restrictive of such provisions,
approximately $45 million of retained earnings was not subject to dividend
restriction at December 31, 1994.
Leases and support agreements The Company participated with other electric
utilities in the construction of the Phase I Hydro-Quebec transmission
facilities in northeastern Vermont, which were completed at a total cost of
approximately $140 million. Under a support agreement relating to the
Company's participation in the facilities, the Company is obligated to pay its
4.42% share of Phase I Hydro-Quebec capital costs over a 20-year recovery
period through and including 2006. The Company also participated in the
construction of Phase II Hydro-Quebec transmission facilities constructed
throughout New England, which were placed in service in November 1990 with a
total cost of approximately $487 million. Under a similar support agreement,
the Company is obligated to pay its 5.132% share of Phase II Hydro-Quebec
capital costs over a 25-year recovery period through and including 2015. All
costs under these support agreements are recorded as purchased transmission
expense in accordance with the Company's rate-making policies. Future minimum
payments will be approximately $3.2 million for each year from 1995 through
2015 and will decline thereafter. The Company's percentage shares of the net
capital cost of these facilities, totaling approximately, $21.6 million, are
classified in the accompanying Consolidated Balance Sheet as "Utility Plant"
and "Long-term Lease Arrangements" (current and non-current).
Minimum rental commitments of the Company under non-cancelable leases as
of December 31, 1994, are not material. Total rental expense entering into
the determination of net income, consisting principally of vehicle and
equipment rentals, was approximately $3.0 million, $3.1 million and $3.3
million for the years 1992 through 1994, respectively.
Legal proceeding On December 30, 1994, the Company and its board of directors
were named as defendants in a complaint filed in the United States District
Court for the District of Vermont by three shareholders. The complaint
alleges, among other things, (i) that F. Ray Keyser, Jr., Chairman of the
Company's board of directors, violated Section 8 of the Clayton Act, 15 U.S.C.
Subchapter 19, which precludes certain interlocking directorships, (ii) that
Mr. Keyser violated his fiduciary duties to the Company's stockholders by
acquiring and operating a series of businesses in competition with the Company
without offering those business opportunities to the Company, (iii) that the
remaining individual defendants violated their fiduciary duties to the
Company's stockholders by failing to analyze, or to cause management to
analyze, diversification into propane and fossil fuels, and by failing to make
the Company an effective competitor of alternative fuel companies, and (iv)
that the Company violated the applicable provision of the Vermont General
Corporation Law by failing to provide a list of the Company's stockholders.
The complaint seeks an unspecified amount of damages (including treble damages
against Mr. Keyser), attorney's fees and costs, a list of the Company's
stockholders, and a court order to enjoin the defendants from alleged
continuing violations of the law. Each of the individual defendants and the
Company itself deny the allegations against them and intend to vigorously
defend the complaint.
Note 14
Non-recurring charge
In addition to the write-offs described in Notes 3 and 11 herein, during
the fourth quarter of 1994, the Company also wrote-off approximately
$2.9 million of costs associated with its proposed new headquarters office
building which reduced after tax earnings by approximately $1.7 million.
Note 15
Unaudited quarterly financial information
The following quarterly financial information is unaudited and includes
all adjustments consisting of normal recurring accruals which are, in the
opinion of management, necessary for a fair statement of results of operations
for such periods. Variations between quarters reflect the seasonal nature of
the Company's business (dollars in thousands, except per share amounts):
Quarter Ended 12 Months
March June September December Ended
1994
Operating revenues $83,885 $57,684 $59,027 $76,562 $277,158
Operating income (loss) $14,367 $ (447) $ 368 $ 6,815 $ 21,103
Net income (loss) $12,608 $(2,003) $ (791) $ 4,986 $ 14,800
Earnings (loss) per share
of common stock $1.04 $(.22) $(.11) $.38 $1.08
1993
Operating revenues $85,319 $56,975 $60,994 $76,101 $279,389
Operating income $16,847 $ 260 $ 679 $ 8,260 $ 26,046
Net income (loss) $14,828 $ (920) $ (354) $ 7,738 $ 21,292
Earnings (loss) per share
of common stock $1.26 $(.14) $(.09) $.61 $1.64
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 1995 Annual Meeting of Stockholders,
consisting of the three nominees listed below, will stand for re-election to a
three-year term expiring in 1998. Proxies will be voted (unless otherwise
instructed) in favor of the election of the three nominees as indicated in the
table below. While it is not anticipated that any of the persons listed will
be unable to serve as a director, if that should occur the proxies will be
voted for such other person or persons as the present Board of Directors shall
determine.
The following table sets forth certain information regarding the three
nominees for Director, as well as all Directors presently serving on the Board
whose terms will expire after the 1995 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.
Served as
Director Principal Occupation and
Name and Age Since Business Experience
Nominees whose terms will expire in 1998:
Luther F. Hackett - 61 1979 President, Hackett, Valine &
MacDonald, Inc., Burlington,
Vermont (Insurance Agents)
F. Ray Keyser, Jr. - 67 1980 Chairman of the Board of
Central Vermont Public
Service Corporation,
Of Counsel, Keyser,
Crowley, Meub, Layden,
Kulig & Sullivan, P.C.
Rutland, Vermont
(Lawyers)
Gordon P. Mills - 58 1980 Chairman, EHV-Weidmann
Industries, Inc.,
St. Johnsbury, Vermont
(Manufacturer of Electric
Transformer Insulation)
Directors whose terms will expire in 1997:
Frederic H. Bertrand - 58 1984 Chairman of the Board and
Chief Executive Officer,
National Life Insurance Co.
Montpelier, Vermont
Mary Alice McKenzie - 37 1992 President and Chief
Executive Officer, John
McKenzie Packing Co., Inc.
Burlington, Vermont
(Manufacturer of Meat
Products)
Robert D. Stout - 68 1985 Retired President and
Chief Executive Officer,
Putnam Memorial Health
Corporation, Bennington,
Vermont
Served as
Director Principal Occupation and
Name and Age Since Business Experience
Directors whose terms will expire in 1996:
Robert P. Bliss, Jr. - 71 1973 President, Bob Bliss, Ltd.
St. Albans, Vermont
(Insurance Industry
Consultants)
Elizabeth Coleman - 57 1990 President, Bennington College,
Bennington, Vermont
Preston Leete Smith - 64 1977 Chief Executive Officer,
S-K-I Ltd., West Lebanon,
New Hampshire (Ski Business)
Thomas C. Webb - 60 1986 President and Chief
Executive Officer, Central
Vermont Public Service
Corporation, Rutland, Vermont
Executive Officers of the Registrant:
Name and Age Office Officer Since
Thomas C. Webb, 60 President and Chief
Executive Officer 1985
Robert H. Young, 47 Executive Vice President
and Chief Operating Officer 1987
Robert de R. Stein, 45 Senior Vice President-Energy
Resources and External Markets 1988
Frederick S. Potter, 49 Vice President-Finance &
Administration and Principal
Financial Officer 1994
Jacquel-Anne Chouinard, 55 Vice President-Human Resources 1986
Thomas J. Hurcomb, 57 Vice President-Marketing and
Public Affairs 1975
Robert G. Kirn, 43 Vice President-Engineering and
Operations 1991
William J. Deehan, 42 Assistant Vice President-Rates
and Economic Analysis 1991
Jonathan W. Booraem, 56 Treasurer 1984
Joseph M. Kraus, 40 Secretary and General Counsel 1987
James M. Pennington, 39 Controller and Principal
Accounting Officer 1993
Mr. Webb joined the Company in 1985 as Executive Vice President - Finance
and Administration and in 1986 was also designated Chief Executive Officer.
He was elected Director, President and Chief Executive Officer on July 1,
1986.
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.
Mr. Stein joined the Company in 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 and assumed his present position in 1994.
Mr. Potter joined the Company in 1994 and has served as Vice President -
Finance and Administration and Principal Financial Officer since that time.
From 1991-1994 he was Vice President at DQE, Inc. and President of its wholly
owned subsidiary, Duquesne Enterprises, Inc. During 1989-1990 he was a senior
investment banker with Bear, Stearns & Co. Inc.
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 and assumed his present position in 1994. 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.
Mr. Deehan joined the Company in 1985. Prior to being elected to his
present position, he served as Director of Rate Administration and
Forecasting.
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.
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 four other most highly compensated executive
officers whose salary and bonus for services rendered to the Company and its
subsidiaries in all capacities for 1994 exceeded $100,000.
I. Summary Compensation Table
Long Term
Compensation
Annual Compensation Awards
- ------------------------------------------------------ ------------
(a) (b) (c) (d) (g) (i)
Securities
Underlying
Option/ All Other
Name and Principal Salary Bonus SARs
Compensation
Position Year ($) 1/ ($)2/ (#) ($) 3/
- ---------------------- ---- ------- ------ ------------ ---------
A. Thomas C. Webb 1994 260,759 0 8,000/0 7,946
President and Chief 1993 248,755 67,183 8,000/0 12,453
Executive Officer 1992 244,694 73,000 6,000/0 17,850
B. Robert H. Young 1994 153,756 0 6,000/0 4,927
Executive Vice President 1993 141,769 35,995 6,000/0 4,533
and Chief Operating 1992 130,667 34,073 4,500/0 4,363
Officer
C. Robert de R. Stein 1994 119,606 0 4,500/0 4,873
Senior Vice President- 1993 114,677 16,804 4,500/0 3,988
Energy Resources and 1992 105,473 18,728 3,000/0 3,472
External Markets
D. Thomas J. Hurcomb 1994 104,115 0 3,000/0 4,534
Vice President 1993 98,382 15,606 3,000/0 4,996
Marketing and 1992 98,649 17,766 3,000/0 4,355
Public Affairs
E. Robert G. Kirn 1994 98,201 0 3,000/0 4,264
Vice President - 1993 93,736 15,750 3,000/0 3,574
Engineering and 1992 93,465 19,869 3,000/0 1,751
Operations
1/ - 1993 and 1994 include 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.
2/ - Includes incentive bonuses awarded by Catamount Energy Corporation,
a wholly owned subsidiary, in 1992 and 1993 as follows:
For A: 1993 - $10,000, 1992 - $5,000, for B: 1993 - $10,000,
1992 - $5,000.
- Includes relocation bonus for E: 1992 - $5,000.
3/ - 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: $5,914; for B: $4,613;
for C: $4,647; for D: $3,968; for E: $3,928.
(ii) Taxable term cost on executive split-dollar insurance.
(An insurance plan that gives both employer and employee an
interest in the policy death benefit on the employee's life.)
For A: $2,032; for B: $314; for C: $226; for D: $566; for
E: $336.
Stock Options.
The following table sets forth stock options granted to the Company's
Chief Executive Officer and the four other most highly compensated executive
officers during 1994 under the Company's 1988 Stock Option Plan for Key
Employees. Under SEC regulations, companies are required to project an
estimate of appreciation of the underlying shares of stock during the option
term. The Company has chosen the Black-Scholes model formula approved by the
SEC. However, the ultimate value will depend on the market value of the
Company's stock at a future date, which may or may not correspond to the
projections below.
II. Options/SAR Grants Table
Option/SAR Grants in Last Fiscal Year
Grant Date
Individual Grants Value
- ------------------ ---------- ---------- -------- ------- ----------
% of
Number of Total
Securities Options/
Underlying SARs
Options/ Granted to Exercise Grant
SARs Employees Or Base Expira- Date
Granted In Fiscal Price tion Present
Name (#) 1/ Year ($/Sh) Date Value 2/
- ------------------ ---------- ---------- -------- ------- ----------
Thomas C. Webb 8,000/0 21.1% $18.4375 5/3/04 $13,920
Robert H. Young 6,000/0 15.8 18.4375 5/3/04 10,440
Robert de R. Stein 4,500/0 11.8 18.4375 5/3/04 7,830
Thomas J. Hurcomb 3,000/0 7.9 18.4375 5/3/04 5,220
Robert G. Kirn 3,000/0 7.9 18.4375 5/3/04 5,220
1/ A total of 38,000 shares were awarded to all plan participants in
1994. Stock Options are exercisable in whole or in part from the
date of the grant for a period of ten years and one day.
2/ Per Black-Scholes model as certified by independent consultant.
The assumptions used for the Model are as follows: Volatility-
.201 based on quarterly prices for the period of 3/31/88 to
12/31/94; Risk free rate of return-7.2%; Dividend Yield-7.7%
over period of 3/31/88 to 12/31/94; and Term of Exercise-10 years.
The following table sets forth stock options exercised by the Company's
Chief Executive Officer and the four other most highly compensated executive
officers during 1994, and the number and value of all unexercised options at
year-end. The value of "in-the-money" options refers to options having an
exercise price which is less than the market price of the Company's common
stock on December 31, 1994.
III. Option/SAR Exercises and Year-end Value Table
Aggregated Option/SAR Exercises in Last Fiscal Year
and FY-End Option/SAR Value
(a) (b) (c) (d) (e)
Number of
Securities Value of
Underlying Unexercised
Unexercised In-the-Money
Options/SARs Options/SARs
At FY-End (#) FY-End ($)
Shares Acquired Value Exercisable/ Exercisable/
Name on Exercise (#) Realized($)1/ Unexercisable Unexercisable
- ------------------ --------------- ------------- ------------- -------------
Thomas C. Webb - - 22,000/0 $0/0
Robert H. Young 4,125 $7,391 16,500/0 0/0
Robert de R. Stein - - 19,500/0 0/0
Thomas J. Hurcomb - - 18,000/0 0/0
Robert G. Kirn - - 11,250/0 0/0
1/ The dollar values in columns (c) and (e) are calculated by determining
the difference between the fair market value of the securities
underlying the options and the exercise or base price of the options
at exercise or fiscal year end, respectively.
Deferred Compensation Plan.
Employees of the Company who are officers are eligible to defer receipt
of a portion of their compensation pursuant to the Company's Deferred
Compensation Plan (the "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. The 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") is a defined benefit plan which 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, 1994, based on Final
Average Earnings for various years of service, assuming the employee would
retire at age 65 in 1995.
Assumed
5-Year Final Years of Service
Average Earnings 15 20 25 30 35
---------------- --------- --------- --------- --------- ---------
$ 80,000 $18,959 $25,278 $31,598 $37,918 $39,918
100,000 24,209 32,278 40,348 48,418 50,918
120,000 29,459 39,278 49,098 58,918 61,918
140,000 34,709 46,278 57,848 69,418 72,918
150,000 37,334(1) 49,778(1) 62,223(1) 74,668(1) 78,418(1)
190,000 37,334(1) 49,778(1) 62,223(1) 74,668(1) 78,418(1)
230,000 37,334(1) 49,778(1) 62,223(1) 74,668(1) 78,418(1)
250,000 37,334(1) 49,778(1) 62,223(1) 74,668(1) 78,418(1)
280,000 37,334(1) 49,778(1) 62,223(1) 74,668(1) 78,418(1)
300,000 37,334(1) 49,778(1) 62,223(1) 74,668(1) 78,418(1)
________
(1) Internal Revenue Code Section 401(a)(17) limits earnings used to calculate
qualified plan benefits to $150,000 for 1994.
Final Average Earnings is the highest five-year average of consecutive
years' Base Salary (item (c) from the Summary Compensation Table with the
exclusion of Mr. Webb s retainer and fees from VELCO) over an employee's
career with the Company.
The amounts above are payable for the life of the retiree only, and would
be reduced on an actuarial basis if survivor options were chosen. In
addition, no Social Security offset applies to amounts above.
The credited years of service at December 31, 1994 under the Plan for
those individuals named in the Summary Compensation Table were as follows:
Mr. Webb, 10 years; Mr. Young, 7 years, 6 months; Mr. Stein, 6 years,
7 months; Mr. Hurcomb, 27 years and Mr. Kirn, 3 years, 8 months.
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. Under this
Plan, the individuals named in the Summary Compensation Table are covered,
while employed, by life insurance at the following multiple of salary:
Mr. Webb, 4 times; Messrs. Young, Stein, Hurcomb and Kirn, 3 times.
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 with the exclusion of Mr. Webb s retainer and fees from
VELCO). A reduced benefit is available at age 60 for officers who attain age
55 with ten years of service. A paid-up life insurance of $100,000 is also
provided to vested retirees under this Plan.
The applicable percentages for the individuals named in Summary
Compensation Table are as follows: Mr. Webb, 44.5%; Messrs. Young, Stein,
Hurcomb and Kirn, 33%.
Shown below is the estimated Company provided benefit payable under the
Plan for those individuals named in the Summary Compensation Table, assuming
they were to retire at age 65:
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
The Plan is financed through the Company's acquisition of corporate-owned
life insurance.
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. Hurcomb 13,900
Employee Savings and Investment Plan.
Effective January 1, 1985 the Company adopted an Employee Savings and
Investment Plan (the Plan ) (also known as a 401(k) Plan) which provides a
means for eligible employees to accumulate savings and investment income
without payment of current income taxes. Presently any employee of the
Company who has completed at least one year of service, as defined in the
Plan, is eligible to participate ( Participant ). An eligible employee who
elects to participate in the Plan may authorize the Company to contribute to
the Plan for his or her account between 1% and 15% of their pre-tax base
compensation for each pay period. For 1994, the Plan limits the maximum
annual deferral to $9,240 per Participant. This maximum is adjusted annually
for inflation by the Internal Revenue Service. The Company matches 100% of
the first 4% of the compensation the Participant contributes to the Plan. A
Participant may direct the investment of his or her Plan account among five
funds specified in the Plan and is at all times fully vested in his or her
Plan account. Generally, distribution of employee contributions is deferred
until the Participant's death, disability, retirement or other termination of
employment, except in cases of financial hardship. Matching employer
contributions, however, may be withdrawn by the Participant at any time and
for any reason, provided either the amount withdrawn has been in the Plan for
at least two years or the Participant has been a member of the Plan for at
least 5 years. Such in-service withdrawals are generally subject to ordinary
income tax and an additional 10% tax plus a mandatory 20% rollover tax
withholding effective January 1, 1993. Distribution of Plan benefits may be
in the form of cash, an annuity, or in certain circumstances, Common Stock of
the Company. Amounts voluntarily deferred by the five highest paid executive
officers are included in compensation listed in Item (c) of the Summary
Compensation Table. Matching Company contributions credited to the Plan
accounts of the individuals referred to during 1994 are set forth in Column 4,
Item (i) in the Summary Compensation Table.
Contracts with Management.
The Company has entered into severance compensation agreements with
Messrs. Webb, Young, Stein, Hurcomb, Kirn and six other officers of the
Company. The agreements have a term of five years provision for renewal.
They provide that in the event of termination of employment, or a significant
change in employment status as defined in the agreement, within three years
following a change in control of the Company, Messrs. Webb, Young, Stein,
Hurcomb, Kirn and three other executive officers will receive 2.999 times and
three other officers will receive two times their average annual compensation
for the preceding five or fewer years of service and certain legal fees and
expenses incurred as a result of termination of employment.
The provisions of the agreement do not apply if the officer retires,
dies, or is disabled, voluntarily resigns, or is dismissed for cause. In
exchange for agreeing to provide consulting services as requested by the
Company for one year and refraining from working in competition with, or for a
competitor of the Company for three years, the agreement permits continued
participation in and retention of benefits under the Deferred Compensation
Plan, Officers' Insurance and Supplemental Retirement Plans, and health and
disability plans. The extent of these provisions depends on an individual's
participation and circumstances, and is specified in each agreement. Those
seven officers with less than 10 years of service would receive a payment
actuarially equivalent to benefits received under the Company's pension plan
at age 65 with ten years of service, less any benefit paid under the pension
plan. The agreements also provide for the payment to officers of an amount
sufficient to offset any federal excise tax on the termination payments under
Section 4999 of the Internal Revenue Code. Non-qualified stock options not
immediately exercisable will become exercisable in the event of a change of
control of the Company as defined in the Plan.
A change of control occurs under the agreement when (1) any person,
corporation, partnership or group acquires 20% or more of the combined voting
power of the Company's outstanding securities; (2) if those members
constituting a majority of the Directors at any given date no longer
constitute a majority of the Directors at the end of a period of two
consecutive years thereafter (unless the nomination of each new director was
approved by a vote of at least two-thirds of the directors in office who were
directors at the beginning of the period); or (3) if a third party acquires
ownership or voting power of 10% or more of the outstanding voting securities
of the Company, and subsequently is a "public utility holding company" within
the meaning of the Public Utility Holding Company Act of 1935, or the Company
loses its exemption from or is required to register under that Act.
During 1989, the Board also approved a severance plan in the event of a
change of control for key managers of the Company not covered by the above
plan. In the event of a change in control as described above and a subsequent
discharge from employment within eighteen months for reason other than cause,
thirty-two managers will receive a severance payment equal to one year's base
salary, outplacement services, and coverage under the Company's medical plan
for one year at Company expense.
The Board of Directors believes that such agreements protect the
stockholders by ensuring officers and key managers can and will act in
stockholders' best interests without regard to personal situations or
concerns. The Board also believes that such agreements will better ensure
retention and recruitment of high caliber officers and key managers.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The following table sets forth the number of shares of Common Stock of
the Company beneficially owned by each director and nominee director, each of
the executive officers named in the Summary Compensation Table and by all the
directors, nominee directors and officers as a group as of January 31, 1995.
Shares of Common Stock
Name Beneficially Owned (1)(2)(3)(4)
-------------------- ----------------------
Frederic H. Bertrand 10,444 (5)
Robert P. Bliss, Jr. 10,573 (6)
Elizabeth Coleman 9,959
Luther F. Hackett 8,533 (7)
Thomas J. Hurcomb 20,773
F. Ray Keyser, Jr. 14,226 (8)
Robert G. Kirn 11,456
Mary Alice McKenzie 6,192 (9)
Gordon P. Mills 44,606 (10)
Preston Leete Smith 8,299
Robert de R. Stein 19,849
Robert D. Stout 11,531
Thomas C. Webb 35,290
Robert H. Young 17,410
All directors and officers
as a group (20) 266,525
No Director, nominee for Director or Executive Officer owns any shares of
the various classes of the Company's outstanding non-voting preferred stock.
(1) No Director, nominee for Director or executive officer owns
beneficially in excess of 1% of CVPS' outstanding Common Stock,
except as otherwise indicated in the footnotes to the table, each
of the named individual possesses sole voting and investment power
over the shares listed.
(2) Includes shares that the named individuals have a right to acquire
pursuant to options granted under the 1988 and 1993 Stock Option
Plans for Non-Employee Directors as follows: Messrs. Bertrand and
Keyser, 9,000 shares; Messrs. Bliss, Mills and Stout, 7,500 shares;
Ms. McKenzie and Mr. Smith, 6,000 shares; Ms. Coleman and Mr. Hackett,
4,500 shares.
(3) Includes shares that the named individuals have a right to acquire
pursuant to options granted under the 1988 Stock Option Plan for
Key Employees as follows: Mr. Hurcomb, 18,000 shares; Mr. Kirn,
11,250 shares; Mr. Stein, 19,500 shares; Mr. Webb, 22,000 shares;
Mr. Young, 16,500 shares; and all Executive Officers as a group,
114,250 shares.
(4) Includes shares that the named individuals hold under the Company's
Employee Savings and Investment and Employee Stock Ownership Plans
as follows: Mr. Hurcomb, 2,759 shares; Mr. Webb, 8,790 shares; and
Mr. Young, 310 shares.
(5) Includes 1,444 shares held jointly with his wife over which Mr. Bertrand
has voting and investment power.
(6) Includes 150 shares held jointly with his wife over which Mr. Bliss has
voting and investment power.
(7) Includes 1,500 shares owned by corporations over which Mr. Hackett has
voting and investment power.
(8) Includes 1,476 shares held jointly with his wife and 3,750 shares held
in a Keogh Trust over which Mr. Keyser has voting and investment power.
(9) Includes 150 shares held jointly with her husband over which Ms. McKenzie
has voting and investment power.
(10) Includes 15,000 shares held in a pension trust over which Mr. Mills has
voting and investment power.
The Company knows of no person, entity or group (within the meaning of
Section 13(d)(3) of the Securities Exchange Act of 1934) which owns
beneficially more than 5% of any class of the Company's outstanding equity
securities.
Reports of Beneficial Ownership
Section 16(a) of the Securities Exchange Act of 1934 requires the
Company's Directors and Officers 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 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
directors, officers and persons who beneficially own more than ten percent
(10%) of the Company's stock to file initial reports of ownership and
subsequent reports of changes in ownership with the SEC and the NYSE. Based
solely on a review of the copies of such reports prepared and filed with the
Commission during 1994 by the Company's Executive Officers and Directors, and
on written representations that no other reports were required the Company
believes its Directors and Executive Officers have complied with all Section
16(a) filing requirements. The Company does not have a ten percent holder.
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)1. The following financial statements for Central
Vermont Public Service Corporation and its
wholly owned subsidiaries are filed as part
of this report: (See Item 8)
1.1 Consolidated Statement of Income, for
each of the three years ended
December 31, 1994
Consolidated Statement of Cash Flows,
for each of the three years ended
December 31, 1994
Consolidated Balance Sheet at December 31,
1994 and 1993
Consolidated Statement of Capitalization
at December 31, 1994 and 1993
Consolidated Statement of Changes in
Common Stock Equity for each of the
three years ended December 31, 1994
Notes to Consolidated Financial Statements
(a)2. Financial Statement Schedules:
2.1 Central Vermont Public Service Corporation and
its wholly owned subsidiaries:
Schedule II - Reserves for each of the
three years ended December 31, 1994
Schedules not included have been omitted because they
are not applicable or the required information is shown
in the financial statements or notes thereto. Separate
financial statements of the Registrant (which is primarily
an operating company) have been omitted since they are
consolidated only with those of totally held subsidiaries.
Separate financial statements of subsidiary companies not
consolidated have been omitted since, if considered in
the aggregate, they would not constitute a significant
subsidiary. Separate financial statements of 50% or less
owned persons for which the investment is accounted for
by the equity method by the Registrant have been omitted
since, if considered in the aggregate, they would not
constitute a significant investment.
(a)3. Exhibits (* denotes filed herewith)
Each document described below is incorporated by reference
to the appropriate exhibit numbers and the Commission file
numbers indicated in parantheses, unless the reference to
the document is marked as follows:
* - Filed herewith.
Exhibit 3 Articles of Incorporation and By-Laws
* 3-1 By-Laws, as amended May 3, 1994.
3-2 Articles of Association, as amended August 11, 1992.
(Exhibit No. 3-2, 1992 10-K, File No. 1-8222)
Exhibit 4 Instruments defining the rights of security holders, including
Indentures
Incorporated herein by reference:
4-1 Mortgage dated October 1, 1929, between the Company and Old
Colony Trust Company, Trustee, securing the Company's First
Mortgage Bonds. (Exhibit B-3, File No. 2-2364)
4-2 Supplemental Indenture dated as of August 1, 1936,
supplemental to 4-1. (Exhibit B-4, File No. 2-2364)
4-3 Copy of Supplemental Indenture dated as of November 15, 1943,
supplemental to 4-1. (Exhibit B-3, File No. 2-5250)
4-4 Copy of Supplemental Indenture dated as of December 1,
1943, supplemental to 4-1. (Exhibit No. B-4, File No.
2-5250)
4-5 Copy of directors' resolutions adopted December 14, 1943,
establishing the Series C Bonds and dealing with other
related matters, supplemental to 4-1. (Exhibit B-5, File
No. 2-5250)
4-6 Copy of Supplemental Indenture dated as of April 1, 1944
supplemental to 4-1. (Exhibit No. B-6, File No. 2-5466)
4-7 Copy of Supplemental Indenture dated as of February 1,
1945, supplemental to 4-1. (Exhibit 7.6, File No. 2-5615)
(22-385)
4-8 Directors' resolutions adopted April 9, 1945, establishing
the Series D Bonds and dealing with other matters, supplemental
to 4-1. (Exhibit 7.8, File No. 2-5615 (22-385)
4-9 Copy of Supplemental Indenture dated as of September 2, 1947,
supplemental to 4-1. (Exhibit 7.9, File No. 2-7489)
4-10 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 4-1. (Exhibit
7.10, File No. 2-8388)
4-11 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 4-1. (Exhibit 7.11,
File No. 2-8388)
4-12 Copy of Supplemental Indenture dated August 1, 1951, and and
directors'resolutions, establishing the Series G Bonds and
dealing with other matters, supplemental to 4-1. (Exhibit 7.12,
File No. 2-9073)
4-13 Copy of Supplemental Indenture dated May 1, 1952, and
directors' resolutions, establishing the Series H Bonds and
dealing with other matters, supplemental to 4-1. (Exhibit
4.3.13, File No. 2-9613)
4-14 Copy of Supplemental Indenture dated as of July 10, 1953,
supplemental to 4-1. (July, 1953 Form 8-K, File No. 1-8222)
4-15 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 4-1. (Exhibit
4.2.16, File No. 2-10959)
4-16 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 4-1. (Exhibit
4.2.16, File No. 2-13321)
4-17 Copy of Supplemental Indenture dated as of March 15, 1960,
supplemental to 4-1. (March, 1960 Form 8-K, File No. 1-8222)
4-18 Copy of Supplemental Indenture dated as of March 1, 1962,
supplemental to 4-1. (March, 1962 Form 8-K, File No. 1-8222)
4-19 Copy of Supplemental Indenture dated as of March 2, 1964,
supplemental to 4-1. (March, 1964 Form 8-K, File No, 1-8222)
4-20 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 4-1. (April, 1965
Form 8-K, File No. 1-8222)
4-21 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 4-1.
(January, 1967 Form 8-K, File No. 1-8222)
4-22 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 4-1. (December,
1967 Form 8-K, File No. 1-8222)
4-23 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 4-1.
(Exhibit B.23, July, 1969 Form 8-K, File No. 1-8222)
4-24 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 4-1.
(Exhibit B.24, January, 1970 Form 8-K, File No. 1-8222)
4-25 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 4-1.
(Exhibit B.25, May, 1971, Form 8-K, File No. 1-8222)
4-26 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 4-1.
(Exhibit B.26, May, 1973, Form 8-K, File No. 1-8222)
4-27 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 4-1.
(Exhibit B.27, April, 1975, Form 8-K, File No. 1-8222)
4-28 Copy of Supplemental Indenture dated as of April 1, 1977,
modifying 4-1. (Exhibit 2.42, File No. 2-58621)
4-29 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 4-1.
(Exhibit 2.43, File No. 2-58621)
4-30 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 4-1. (Exhibit B-30, 1980 Form 10-K,
File No. 1-8222)
4-31 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 4-1. (Exhibit B-31, 1980 Form 10-K,
File No. 1-8222)
4-32 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 4-1.
(Exhibit B-32, 1981 Form 10-K, File No. 1-8222)
4-45 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 4-1. (Exhibit B-45, 1983 Form 10-K, File No. 1-8222)
4-46 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, File No. 1-8222)
4-47 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 4-1. (Exhibit B-47,
1985 Form 10-K, File No. 1-8222)
4-48 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, File No. 1-8222)
4-49 Stock-Purchase Agreement between Vermont Electric Power
Company, Inc. and the Company dated August 11, 1986 relative
to purchase of Class C Preferred Stock. (Exhibit B-49, 1986
Form 10-K, File No. 1-8222)
4-50 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 4-1. (Exhibit 4-50,
1989 Form 10-K, File No. 1-8222)
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 4-1. (Exhibit 4-51, 1990 Form 10-K, File No. 1-8222)
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 4-1.
(Exhibit 4-52, 1991 Form 10-K, File No. 1-8222)
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, File No. 1-8222)
Exhibit 10 Material Contracts (*Denotes filed herewith)
Incorporated herein by reference:
10.l Copy of firm power Contract dated August 29, 1958, and
supplements thereto dated September 19, 1958, October 7, 1958,
and October 1, 1960, between the Company and the State
of Vermont (the "State"). (Exhibit C-1, File No. 2-17184)
10.1.1 Agreement setting out Supplemental NEPOOL Understandings
dated as of April 2, 1973. (Exhibit C-22, File No.
5-50198)
10.2 Copy of Transmission Contract dated June 13, 1957, between Velco
and the State, relating to transmission of power. (Exhibit
10.2, 1993 Form 10-K, File No. 1-8222)
10.2.1 Copy of letter agreement dated August 4, 1961, between
Velco and the State. (Exhibit C-3, File No. 2-26485)
10.2.2 Amendment dated September 23, 1969. (Exhibit C-4, File
No. 2-38161)
10.2.3 Amendment dated March 12, 1980. (Exhibit C-92, 1982
Form 10-K, File No. 1-8222)
10.2.4 Amendment dated September 24, 1980. (Exhibit C-93, 1982
Form 10-K, File No. 1-8222)
10.3 Copy of subtransmission contract dated August 29, 1958, between
Velco and the Company (there are seven similar contracts between
Velco and other utilities). (Exhibit 10.3, 1993 Form 10-K,
Form No. 1-8222)
10.3.1 Copies of Amendments dated September 7, 196l, November 2,
1967, March 22, 1968, and October 29, 1968. (Exhibit
C-6, File No. 2-32917)
10.3.2 Amendment dated December 1, 1972. (Exhibit 10.3.2, 1993
Form 10-K, File No. 1-8222)
10.4 Copy of Three-Party Agreement dated September 25, 1957, between
the Company, Green Mountain and Velco. (Exhibit C-7, File No.
2-17184)
10.4.1 Superseding Three Party Power Agreement dated January 1,
1990. (Exhibit 10-201, 1990 Form 10-K, File No. 1-8222)
10.4.2 Agreement Amending Superseding Three Party Power
Agreement dated May 1, 1991. (Exhibit 10.4.2, 1991 Form
10-K, File No. 1-8222)
10.5 Copy of firm power Contract dated December 29, 1961, between the
Company and the State, relating to purchase of Niagara Project
power. (Exhibit C-8, File No. 2-26485)
10.5.1 Amendment effective as of January 1, 1980. (Exhibit
10.5.1, 1993 Form 10-K, File No. 1-8222)
10.6 Copy of agreement dated July 16, 1966, and letter supplement
dated July 16, 1966, between Velco and Public Service Company of
New Hampshire relating to purchase of single unit power from
Merrimack II. (Exhibit C-9, File No. 2-26485)
10.6.1 Copy of Letter Agreement dated July 10, 1968, modifying
Exhibit A. Exhibit C-10, File No. 2-32917)
10.7 Copy of Capital Funds Agreement between the Company and Vermont
Yankee dated as of February 1, 1968. (Exhibit C-11, File No.
70-4611)
10.7.1 Copy of Amendment dated March 12, 1968. (Exhibit C-12,
File No. 70-4611)
* 10.7.2 Copy of Amendment dated September 1, 1993
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. (10.8.1, 1993 Form
10-K, File No. 1-8222)
10.8.2 Copy of Additional Power Contract dated February 1,
1984. (Exhibit C-123, 1984 Form 10-K, File No. 1-8222)
10.8.3 Amendment No. 3 to Vermont Yankee Power Contract,
dated April 24, 1985. (Exhibit 10-144, 1986 Form 10-K,
File No. 1-8222)
10.8.4 Amendment No. 4 to Vermont Yankee Power Contract,
dated June 1, 1985. (Exhibit 10-145, 1986 Form 10-K,
File No. 1-8222)
10.8.5 Amendment No. 5 dated May 6, 1988. (Exhibit 10-179,
1988 Form 10-K, File No. 1-8222)
10.8.6 Amendment No. 6 dated May 6, 1988. (Exhibit 10-180,
1988 Form 10-K, File No. 1-8222)
10.8.7 Amendment No. 7 dated June 15, 1989. (Exhibit 10-195,
1989 Form 10-K, File No. 1-8222)
10.9 Copy of Capital Funds Agreement between the Company and Maine
Yankee dated as of May 20, 1968. (Exhibit C-14, File No.
70-4658)
10.9.1 Amendment No. 1 dated August 1, 1985. (Exhibit C-125,
1984 Form 10-K, File No. 1-8222)
10.10 Copy of Power Contract between the Company and Maine Yankee
dated as of May 20, 1968. (Exhibit C-15, File No. 70-4658)
10.10.1 Amendment No. 1 dated March 1, 1984. (Exhibit C-112,
1984 Form 10-K, File No. 1-8222)
10.10.2 Amendment No. 2 effective January 1, 1984. (Exhibit
C-113, 1984 Form 10-K, File No. 1-8222)
10.10.3 Amendment No. 3 dated October 1, 1984. (Exhibit
C-114, 1984 Form 10-K, File No. 1-8222)
10.10.4 Additional Power Contract dated February 1, 1984.
(Exhibit C-126, 1985 Form 10-K, File No. 1-8222)
10.11 Copy of Agreement dated January 17, 1968, between Velco and
Public Service Company of New Hampshire relating to purchase of
additional unit power from Merrimack II. (Exhibit C-16, File
No. 2-32917)
10.12 Copy of Agreement dated February 10, 1968 between the Company
and Velco relating to purchase by Company of Merrimack II unit
power. (There are 25 similar agreements between Velco and
other utilities.) (Exhibit C-17, File No. 2-32917)
10.13 Copy of Three-Party Power Agreement dated as of November 21,
1969, among the Company, Velco, and Green Mountain relating
to purchase and sale of power from Vermont Yankee Nuclear
Power Corporation. (Exhibit C-18, File No. 2-38161)
10.13.1 Amendment dated June 1, 1981. (Exhibit 10.13.1, 1993
Form 10-K, File No. 1-8222)
10.14 Copy of Three-Party Transmission Agreement dated as of
November 21, 1969, among the Company, Velco, and Green Mountain
providing for transmission of power from Vermont Yankee Nuclear
Power Corporation. (Exhibit C-19, File No. 2-38161)
10.14.1 Amendment dated June 1, 1981. (Exhibit 10.14.1, 1993
Form 10-K, File No. 1-8222)
10.15 Copy of Stockholders Agreement dated September 25, 1957,
between the Company, Velco, Green Mountain and Citizens
Utilities Company. (Exhibit No. C-20, File No. 70-3558)
10.16 New England Power Pool Agreement dated as of September 1, 1971,
as amended to November 1, 1975. (Exhibit C-21, File No.
2-55385)
10.16.1 Amendment dated December 31, 1976. (Exhibit 10.16.1
1993 Form 10-K, File No. 1-8222)
10.16.2 Amendment dated January 23, 1977. (Exhibit 10.16.2,
1993 Form 10-K, File No. 1-8222)
10.16.3 Amendment dated July 1, 1977. (Exhibit 10.16.3, 1993
Form 10-K, File No. 1-8222)
10.16.4 Amendment dated August 1, 1977. (Exhibit 10.16.4,
1993 Form 10-K, File No. 1-8222)
10.16.5 Amendment dated August 15, 1978. (Exhibit 10.16.5,
1993 Form 10-K, File No. 1-8222)
10.16.6 Amendment dated January 31, 1979. (Exhibit 10.16.6,
1993 Form 10-K, File No. 1-8222)
10.16.7 Amendment dated Feburary 1, 1980. (Exhibit 10.16.7,
1993 Form 10-K, File No. 1-8222)
10.16.8 Amendment dated December 31, 1976. (Exhibit 10.16.8,
1993 Form 10-K, File No. 1-8222)
10.16.9 Amendment dated January 31, 1977. (Exhibit 10.16.9,
1993 Form 10-K, File No. 1-8222)
10.16.10 Amendment dated July 1, 1977. (Exhibit 10.16.10, 1993
Form 10-K, File No. 1-8222)
10.16.11 Amendment dated August 1, 1977. (Exhibit 10.16.11,
1993 Form 10-K, File No. 1-8222)
10.16.12 Amendment dated August 15, 1978. (Exhibit 10.16.12,
1993 Form 10-K, File No. 1-8222)
10.16.13 Amendment dated January 31, 1980. (Exhibit 10.16.13,
1993 Form 10-K, File No. 1-8222)
10.16.14 Amendment dated February 1, 1980. (Exhibit 10.16.14,
1993 Form 10-K, File No. 1-8222)
10.16.15 Amendment dated September 1, 1981. (Exhibit 10.16.15,
1993 Form 10-K, File No. 1-8222)
10.16.16 Amendment dated December 1, 1981. (Exhibit 10.16.16,
1993 Form 10-K, File No. 1-8222)
10.16.17 Amendment dated June 15, 1983. (Exhibit 10.16.17,
1993 Form 10-K, File No. 1-8222)
10.16.18 Amendment dated September 1, 1985. (Exhibit 10-160,
1986 Form 10-K, File No. 1-8222)
10.16.19 Amendment dated April 30, 1987. (Exhibit 10-172, 1987
Form 10-K, File No. 1-8222)
10.16.20 Amendment dated March 1, 1988. (Exhibit 10-178, 1988
Form 10-K, File No. 1-8222)
10.16.21 Amendment dated March 15, 1989. (Exhibit 10-194, 1989
Form 10-K, File No. 1-8222)
10.16.22 Amendment dated October 1, 1990. (Exhibit 10-203,
1990 Form 10-K, File No. 1-8222)
10.16.23 Amendment dated September 15, 1992. (Exhibit
10.16.23, 1992 Form 10-K, File No. 1-8222)
10.16.24 Amendment dated May 1, 1993. (Exhibit 10.16.24, 1993
Form 10-K, File No. 1-8222)
10.16.25 Amendment dated June 1, 1993. (Exhibit 10.16.25, 1993
Form 10-K, File No. 1-8222)
* 10.16.26 Amendment dated June 1, 1994.
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.
(Exhibit C-32, File No. 2-55450)
10.17.10 Amendment 23 dated as of 1975. (Exhibit C-50, 1975
Form 10-K, File No. 1-8222)
10.18 Agreement for Sharing Costs Associated with Pilgrim Unit No.2
Transmission dated October 13, 1972, among Boston Edison
Company and other utilities including the Company. (Exhibit
C-33, File No. 2-45990)
10.18.1 Addendum dated as of October 1, 1974, by which Green
Mountain Power Corporation became a party thereto.
(Exhibit C-34, File No. 2-52177)
10.18.2 Addendum dated as of January 17, 1975, by which
Burlington Electric Department became a party thereto.
(Exhibit C-35, File No. 2-55458)
10.19 Agreement dated as of May 1, 1973, for Joint Ownership,
Construction and Operation of New Hampshire Nuclear Units among
Public Service Company of New Hampshire and other utilities,
including Velco. (Exhibit C-36, File No. 2-48966)
10.19.1 Amendments dated May 24, 1974, June 21, 1974,
September 25, 1974, October 25, 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.
(Exhibit C-89, File No. 2-68168)
10.19.12 Thirteenth Amendment dated as of December 31, 1980.
(Exhibit C-90, File No. 2-70579)
10.19.13 Fourteenth Amendment dated as of June 1, 1982.(Exhibit
C-104, 1982 Form 10-K, File No. 1-8222)
10.19.14 Fifteenth Amendment dated April 27, 1984. (Exhibit
10-134, 1986 Form 10-K, File No. 1-8222)
10.19.15 Sixteenth Amendment dated June 15, 1984. (Exhibit
10-135, 1986 Form 10-K, File No. 1-8222)
10.19.16 Seventeenth Amendment dated March 8, 1985. (Exhibit
10-136, 1986 Form 10-K, File No. 1-8222)
10.19.17 Eighteenth Amendment dated March 14, 1986. (Exhibit
10-137, 1986 Form 10-K, File No. 1-8222)
10.19.18 Nineteenth Amendment dated May 1, 1986. (Exhibit
10-138, 1986 Form 10-K, File No. 1-8222)
10.19.19 Twentieth Amendment dated September 19, 1986.
(Exhibit 10-139, 1986 Form 10-K, File No. 1-8222)
10.19.20 Amendment No. 22 dated January 13, 1989. (Exhibit
10-193, 1989 Form 10-K, File No. 1-8222)
10.20 Transmission Support Agreement dated as of May 1, 1973, among
Public Service Company of New Hampshire and other utilities,
including Velco, with respect to New Hampshire Nuclear Units.
(Exhibit C-39, File No. 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, File No. 1-8222)
10.22 Preliminary Agreement dated as of July 5, 1974, with respect to
1981 Montague Nuclear Generating Units. (Exhibit C-44, File
No. 2-51733)
10.22.1 Amendment dated June 30, 1975. (Exhibit C-45, File
No. 2-54449)
10.23 Agreement for Joint Ownership, Construction and Operation of
William F. Wyman Unit No. 4 dated November 1, 1974, among
Central Maine Power Company and other utilities including the
Company. (Exhibit C-46, File No. 2-52900)
10.23.1 Amendment dated as of June 30, 1975. (Exhibit C-47,
File No. 2-55458)
10.23.2 Instrument of Transfer dated July 30, 1975, assigning
a partial interest from Velco to the Company.
(Exhibit C-48, File No. 2-55458)
10.24 Transmission Agreement dated November 1, 1974, among Central
Maine Power Company and other utilities including the Company
with respect to William F. Wyman Unit No. 4. (Exhibit C-49,
File No. 2-54449)
10.25 Copy of Power Contract between the Company and Yankee Atomic
dated as of June 30, 1959. (Exhibit C-61, 1981 Form 10-K,
File No. 1-8222)
10.25.1 Revision dated April 1, 1975. (Exhibit C-61, 1981
Form 10-K, File No. 1-8222)
10.25.2 Amendment dated May 6, 1988. (Exhibit 10-181, 1988
Form 10-K, File No. 1-8222)
10.25.3 Amendment dated June 26, 1989. (Exhibit 10-196, 1989
Form 10-K, File No. 1-8222)
10.25.4 Amendment dated July 1, 1989. (Exhibit 10-197, 1989
Form 10-K, File No. 1-8222)
10.25.5 Amendment dated February 1, 1992 (Exhibit 10.25.5,
1992 Form 10-K, File No. 1-8222)
10.26 Copy of Transmission Contract between the Company and Yankee
Atomic dated as of June 30, 1959. (Exhibit C-63, 1981 Form
10-K, File No. 1-8222)
10.27 Copy of Power Contract between the Company and Connecticut
Yankee dated as of June 1, 1964. (Exhibit C-64, 1981 Form
10-K, File No. 1-8222)
10.27.1 Supplementary Power Contract dated March 1, 1978.
(Exhibit C-94, 1982 Form 10-K, File No. 1-8222)
10.27.2 Amendment dated August 22, 1980. (Exhibit C-95,
1982 Form 10-K, File No. 1-8222)
10.27.3 Amendment dated October 15, 1982. (Exhibit C-96,
1982 Form 10-K, File No. 1-8222)
10.27.4 Second Supplementary Power Contract dated April 30,
1984. (Exhibit C-115, 1984 Form 10-K, File No.
1-8222)
10.27.5 Additional Power Contract dated April 30, 1984.
(Exhibit C-116, 1984 Form 10-K, File No. 1-8222)
10.28 Copy of Transmission Contract between the Company and
Connecticut Yankee dated as of July 1, 1964. (Exhibit C-65,
1981 Form 10-K, File No. 1-8222)
10.29 Copy of Capital Funds Agreement between the Company and
Connecticut Yankee dated as of July 1, 1964. (Exhibit C-66,
1981 Form 10-K, File No. 1-8222)
10.29.1 Copy of Capital Funds Agreement between the Company
and Connecticut Yankee dated as of September 1, 1964.
(Exhibit C-67, 1981 Form 10-K, File No. 1-8222)
10.30 Copy of Five-Year Capital Contribution Agreement between the
Company and Connecticut Yankee dated as of November 1, 1980.
(Exhibit C-68, 1981 Form 10-K, File No. 1-8222)
10.31 Form of Guarantee Agreement dated as of November 7, 1981, among
certain banks, Connecticut Yankee and the Company, relating to
revolving credit notes of Connecticut Yankee. (Exhibit C-69,
1981 Form 10-K, File No. 1-8222)
10.32 Form of Guarantee Agreement dated as of November 13, 1981,
between The Connecticut Bank and Trust Company, as Trustee, and
the Company, relating to debentures of Connecticut Yankee.
(Exhibit C-70, 1981 Form 10-K, File No. 1-8222)
10.33 Form of Guarantee Agreement dated as of November 5, 1981,
between Bankers Trust Company, as Trustee of the Vernon Energy
Trust, and the Company, relating to Vermont Yankee Nuclear Fuel
Sale Agreement. (Exhibit C-71, 1981 Form 10-K, File No.
1-8222)
10.34 Preliminary Vermont Support Agreement re Quebec Interconnection
between Velco and among seventeen Vermont Utilities dated
May 1, 1981. (Exhibit C-97, 1982 Form 10-K, File No. 1-8222)
10.34.1 Amendment dated June 1, 1982. (Exhibit C-98, 1982
Form 10-K, File No. 1-8222)
10.35 Vermont Participation Agreement for Quebec Interconnection
between Velco and among seventeen Vermont Utilities dated
July 15, 1982. (Exhibit C-99, 1982 Form 10-K, File No. 1-8222)
10.35.1 Amendment No. 1 dated January 1, 1986. (Exhibit
C-132, 1986 Form 10-K, File No. 1-8222)
10.36 Vermont Electric Transmission Company Capital Funds Support
Agreement between Velco and among sixteen Vermont Utilities
dated July 15, 1982. (Exhibit C-100, 1982 Form 10-K, File No.
1-8222)
10.37 Vermont Transmission Line Support Agreement, Vermont Electric
Transmission Company and twenty New England Utilities dated
December 1, 1981, as amended by Amendment No. 1 dated June 1,
1982, and by Amendment No. 2 dated November 1, 1982. (Exhibit
C-101, 1982 Form 10-K, File No. 1-8222)
10.37.1 Amendment No. 3 dated January 1, 1986. (Exhibit
10-149, 1986 Form 10-K, File No. 1-8222)
10.38 Phase 1 Terminal Facility Support Agreement between New England
Electric Transmission Corporation and twenty New England
Utilities dated December 1, 1981, as amended by Amendment No. 1
dated as of June 1, 1982 and by Amendment No. 2 dated as of
November 1, 1982. (Exhibit C-102, 1982 Form 10-K, File No.
1-8222)
10.39 Power Purchase Agreement between Velco and CVPS dated June 1,
1981. (Exhibit C-103, 1982 Form 10-K, File No. 1-8222)
10.40 Agreement for Joint Ownership, Construction and Operation of
the Joseph C. McNeil Generating Station by and between City of
Burlington Electric Department, Central Vermont Realty, Inc.
and Vermont Public Power Supply Authority dated May 14, 1982.
(Exhibit C-107, 1983 Form 10-K, File No. 1-8222)
10.40.1 Amendment No. 1 dated October 5, 1982. (Exhibit
C-108, 1983 Form 10-K, File No. 1-8222)
10.40.2 Amendment No. 2 dated December 30, 1983. (Exhibit
C-109, 1983 Form 10-K, File No. 1-8222)
10.40.3 Amendment No. 3 dated January 10, 1984. (Exhibit
10-143, 1986 Form 10-K, File No. 1-8222)
10.41 Transmission Service Contract between Central Vermont Public
Service Corporation and The Vermont Electric Generation &
Transmission Cooperative, Inc. dated May 14, 1984. (Exhibit
C-111, 1984 Form 10-K, File No. 1-8222)
10.42 Copy of Highgate Transmission Interconnection Preliminary
Support Agreement dated April 9, 1984. (Exhibit C-117, 1984
Form 10-K, File No. 1-8222)
10.43 Copy of Allocation Contract for Hydro-Quebec Firm Power dated
July 25, 1984. (Exhibit C-118, 1984 Form 10-K, File No.
1-8222)
10.43.1 Tertiary Energy for Testing of the Highgate HVDC
Station Agreement, dated September 20, 1985. (Exhibit
C-129, 1985 Form 10-K, File No. 1-8222)
10.44 Copy of Highgate Operating and Management Agreement dated
August 1, 1984. (Exhibit C-119, 1986 Form 10-K, File No.
1-8222)
10.44.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-152,
1986 Form 10-K, File No. 1-8222)
10.44.2 Amendment No. 2 dated November 13, 1986. (Exhibit
10-167, 1987 Form 10-K, File No. 1-8222)
10.44.3 Amendment No. 3 dated January 1, 1987. (Exhibit
10-168, 1987 Form 10-K, File No. 1-8222)
10.45 Copy of Highgate Construction Agreement dated August 1, 1984.
(Exhibit C-120, 1984 Form 10-K, File No. 1-8222)
10.45.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-151,
1986 Form 10-K, File No. 1-8222)
10.46 Copy of Agreement for Joint Ownership, Construction and
Operation of the Highgate Transmission Interconnection.
(Exhibit C-121, 1984 Form 10-K, File No. 1-8222)
10.46.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-153,
1986 Form 10-K, File No. 1-8222)
10.46.2 Amendment No. 2 dated April 18, 1985. (Exhibit
10-154, 1986 Form 10-K, File No. 1-8222)
10.46.3 Amendment No. 3 dated February 12, 1986. (Exhibit
10-155, 1986 Form 10-K, File No. 1-8222)
10.46.4 Amendment No. 4 dated November 13, 1986. (Exhibit
10-169, 1987 Form 10-K, File No. 1-8222)
10.46.5 Amendment No. 5 and Restatement of Agreement dated
January 1, 1987. (Exhibit 10-170, 1987 Form 10-K,
File No. 1-8222)
10.47 Copy of the Highgate Transmission Agreement dated August 1,
1984. (Exhibit C-122, 1984 Form 10-K, File No. 1-8222)
10.48 Copy of Preliminary Vermont Support Agreement Re: Quebec
Interconnection - Phase II dated September 1, 1984. (Exhibit
C-124, 1984 Form 10-K, File No. 1-8222)
10.48.1 First Amendment dated March 1, 1985. (Exhibit C-127,
1985 Form 10-K, File No. 1-8222)
10.49 Vermont Transmission and Interconnection Agreement between New
England Power Company and Central Vermont Public
Service Corporation and Green Mountain Power Corporation with
the consent of Vermont Electric Power Company, Inc., dated
May 1, 1985. (Exhibit C-128, 1985 Form 10-K, File No. 1-8222)
10.50 Service Contract Agreement between the Company and the State of
Vermont for distribution and sale of energy from St. Lawrence
power projects ("NYPA Power") dated as of June 25, 1985.
(Exhibit C-130, 1985 Form 10-K, File No. 1-8222)
10.50.1 Lease and Operating Agreement between the Company and
the State of Vermont dated as of June 25, 1985.
(Exhibit C-131, 1985 Form 10-K, File No. 1-8222)
10.51 System Sales & Exchange Agreement Between Niagara Mohawk Power
Corporation and Central Vermont Public Service Corporation
dated October 1, 1986. (Exhibit C-133, 1986 Form 10-K, File
No. 1-8222)
10.54 Transmission Agreement between Vermont Electric Power Company,
Inc. and Central Vermont Public Service Corporation dated
January 1, 1986. (Exhibit 10-146, 1986 Form 10-K, File No.
1-8222)
10.55 1985 Four-Party Agreement between Vermont Electric Power
Company, Central Vermont Public Service Corporation, Green
Mountain Power Corporation and Citizens Utilities dated July 1,
1985. (Exhibit 10-147, 1986 Form 10-K, File No. 1-8222)
10.55.1 Amendment dated February 1, 1987. (Exhibit 10-171,
1987 Form 10-K, File No. 1-8222)
10.56 1985 Option Agreement between Vermont Electric Power Company,
Central Vermont Public Service Corporation, Green Mountain
Power Corporation and Citizens Utilities dated December 27,
1985. (Exhibit 10-148, 1986 Form 10-K, File No. 1-8222)
10.56.1 Amendment No. 1 dated September 28, 1988. (Exhibit
10-182, 1988 Form 10-K, File No. 1-8222)
10.56.2 Amendment No. 2 dated October 1, 1991. (Exhibit
10.56.2, 1991 Form 10-K, File No. 1-8222)
* 10.56.3 Amendment No. 3 dated December 31, 1994
10.57 Highgate Transmission Agreement dated August 1, 1984 by and
between the owners of the project and the Vermont electric
distribution companies. (Exhibit 10-156, 1986 Form 10-K, File
No. 1-8222)
10.57.1 Amendment No. 1 dated September 22, 1985. (Exhibit
10-157, 1986 Form 10-K, File No. 1-8222)
10.58 Vermont Support Agency Agreement re: Quebec Interconnection -
Phase II between Vermont Electric Power Company, Inc. and
participating Vermont electric utilities dated June 1, 1985.
(Exhibit 10-158, 1986 Form 10K, File No. 1-8222)
10.58.1 Amendment No. 1 dated June 20, 1986. (Exhibit 10-159,
1986 Form 10-K, File No. 1-8222)
10.59 Indemnity Agreement B-39 dated May 9, 1969 with amendments 1-16
dated April 17, 1970 thru April 16, 1985 between licensees of
Millstone Unit No. 3 and the Nuclear Regulatory Commission.
(Exhibit 10-161, 1986 Form 10-K, File No. 1-8222)
10.59.1 Amendment No. 17 dated November 25, 1985. (Exhibit
10-162, 1986 Form 10-K, File No. 1-8222)
10.62 Contract for the Sale of 50MW of firm power between
Hydro-Quebec and Vermont Joint Owners of Highgate Facilities
dated February 23, 1987. (Exhibit 10-173, 1987 Form 10-K,
File No. 1-8222)
10.63 Interconnection Agreement between Hydro-Quebec and Vermont
Joint Owners of Highgate facilities dated February 23, 1987.
(Exhibit 10-174, 1987 Form 10-K, File No. 1-8222)
10.63.1 Amendment dated September 1, 1993 (Exhibit 10.63.1,
1993 Form 10-K, File No. 1-8222)
10.64 Firm Power and Energy Contract by and between Hydro-Quebec and
Vermont Joint Owners of Highgate for 500MW dated December 4,
1987. (Exhibit 10-175, 1987 Form 10-K, File No. 1-8222)
10.64.1 Amendment No. 1 dated August 31, 1988. (Exhibit
10-191, 1988 Form 10-K, File No. 1-8222)
10.64.2 Amendment No. 2 dated September 19, 1990. (Exhibit
10-202, 1990 Form 10-K, File No. 1-8222)
10.64.3 Firm Power & Energy Contract dated January 21, 1993
by and between Hydro-Quebec and Central Vermont
Public Service Corporation for the sale back of 25 MW
of power. (Exhibit 10.64.3, 1992 Form 10-K, File No.
1-8222)
10.64.4 Firm Power & Energy Contract dated January 21, 1993
by and between Hydro-Quebec and Central Vermont Public
Service Corporation for the sale back of 50 MW of
power. (Exhibit 10.64.4, 1992 Form 10-K, File No.
1-8222)
10.66 Hydro-Quebec Participation Agreement dated April 1, 1988 for
600 MW between Hydro-Quebec and Vermont Joint Owners of
Highgate. (Exhibit 10-177, 1988 Form 10-K, File No. 1-8222)
10.67 Sale of firm power and energy (54MW) between Hydro-Quebec and
Vermont Utilities dated December 29, 1988. (Exhibit 10-183,
1988 Form 10-K, File No. 1-8222)
10.75 Receivables Purchase Agreement between Central Vermont Public
Service Corporation, Central Vermont Public Service Corporation
as Service Agent and The First National Bank of Boston dated
November 29, 1988. (Exhibit 10-192, 1988 Form 10-K)
10.75.1 Agreement Amendment No. 1 dated December 21, 1988
(Exhibit 10.75.1, 1993 Form 10-K, File No. 1-8222)
10.75.2 Letter Agreement dated December 4, 1989
(Exhibit 10.75.2, 1993 Form 10-K, File No. 1-8222)
10.75.3 Agreement Amendment No. 2 dated November 29, 1990
(Exhibit 10.75.3, 1993 Form 10-K, File No. 1-8222)
10.75.4 Agreement Amendment No. 3 dated November 29, 1991
(Exhibit 10.75.4, 1993 Form 10-K, File No. 1-8222)
10.75.5 Agreement Amendment No. 4 dated November 29, 1992
(Exhibit 10.75.5, 1993 Form 10-K, File No. 1-8222)
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
A 10.68 Stock Option Plan for Non-Employee Directors dated July 18,
1988. (Exhibit 10-184, 1988 Form 10-K, File No. 1-8222)
A 10.69 Stock Option Plan for Key Employees dated July 18, 1988.
(Exhibit 10-185, 1988 Form 10-K, File No. 1-8222)
A 10.70 Officers Supplemental Insurance Plan authorized July 9, 1984.
(Exhibit 10-186, 1988 Form 10-K, File No. 1-8222)
A 10.71 Officers Supplemental Deferred Compensation Plan dated
November 4, 1985. (Exhibit 10-187, 1988 Form 10-K, File
No. 1-8222)
A 10.72 Directors' Supplemental Deferred Compensation Plan dated
November 4, 1985. (Exhibit 10-188, 1988 Form 10-K, File No.
1-8222)
A 10.73 Management Incentive Compensation Plan as adopted September 9,
1985. (Exhibit 10-189, 1988 Form 10-K, File No. 1-8222)
A 10.73.1 Revised Management Incentive Plan as adopted
February 5, 1990. (Exhibit 10-200, 1989 Form 10-K,
File No. 1-8222)
A 10.74 Officers' Change of Control Agreements as approved October 3,
1988. (Exhibit 10-190, 1988 Form 10-K, File No. 1-8222)
A 10.78 Stock Option Plan for Non-Employee Directors dated April 30,
1993 (Exhibit 10.78, 1993 Form 10-K, File No. 1-8222)
A 10.79 Officers Insurance Plan dated November 15, 1993
(Exhibit 10.79, 1993 Form 10-K, File No. 1-8222)
A 10.80 Directors'Supplemental Deferred Compensation Plan dated
(Exhibit 10.80, 1993 Form 10-K, File No. 1-8222)
A 10.81 Officers' Supplemental Deferred Compensation Plan dated
(Exhibit 10.81, 1993 Form 10-K, File No. 1-8222)
A - Compensation related plan, contract, or arrangement.
16. Change in certifying accountant (July 1, 1985 Form 8-K, File No.
1-8222)
18. Letter re change in accounting principles (1980 3rd Quarter Form 10-Q,
File No. 1-8222)
21. Subsidiaries of the Registrant
* 21.1 List of Subsidiaries of Registrant
23. Consents of Experts and Counsel
* 23.1 Consent of Independent Public Accountants
27. Financial Data Schedule
(b) Reports on Form 8-K:
The Company filed the following reports on Form 8-K during
the quarter ended December 31, 1994:
1. Item 5. Other Events, dated October 31, 1994 re:
Retail Rate Order.
2. Item 5. Other Events, dated November 9, 1994 re:
Third quarter 1994 report to shareholders and a
press release reporting a new corporate strategy.
Item 7. Financial Statements, Pro Forma Financial
Information and Exhibits. Exhibit Number 13,
Letter to Shareholders. Exhibit Number 20,
Press Release.
3. Item 5. Other Events, dated December 30, 1994 re:
Legal proceeding.
Report of Independent Public Accountants
To the Board of Directors of
Central Vermont Public Service Corporation:
We have audited, in accordance with generally accepted auditing
standards, the consolidated financial statements included in Central Vermont
Public Service Corporation's annual report to shareholders, included in this
Form 10-K, and have issued our report thereon dated February 6, 1995. Our
audit was made for the purpose of forming an opinion on those statements taken
as a whole. The schedule listed in the index above is the responsibility of
the Company's management and is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audit of the basic consolidated financial statements
and, in our opinion, fairly state, in all material respects, the consolidated
financial data required to be set forth therein in relation to the basic
consolidated financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Boston, Massachusetts
February 6, 1995
Schedule II
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 1994
Additions
--------------------
Balance at Charged to Charged Balance at
beginning costs and to other end of
of year expenses accounts Deductions year
---------- ---------- -------- ---------- ----------
Reserves deducted from assets
to which they apply:
$ 71,210(1)
335,718(2)
Reserve for uncollectivle --------
accounts receivable $ 936,080 $547,490 $406,928 $ 922,766(3) $ 967,732
========== ======== ======== ========== ==========
Accumulated depreciation of
miscellaneous properties:
Rental water heater program $3,428,944 $265,309 - $ 243,969(4) $3,450,284
Other 68,153 145,134(5) - - 213,287
---------- -------- ---------- ----------
$3,497,097 $410,443 $ 243,969 $3,663,571
Reserve shown separately:
Injuries and damages reserve $ 225,580 - - - $ 225,580
========== ==========
(1) Amount due from collection agency.
(2) Collections of accounts previously written off.
(3) Uncollectible accounts written off.
(4) Retirements of rental water heaters.
(5) Includes reclassification of $67,201 of the Company's wholly owned subsidiary, SmartEnergy
Services, Inc.'s depreciation expense from its water heater program to other non-utility
property.
Schedule II
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 1993
Additions
--------------------
Balance at Charged to Charged Balance at
beginning costs and to other end of
of year expenses accounts Deductions year
---------- ---------- -------- ---------- ----------
Reserves deducted from assets
to which they apply:
$ 64,809(1)
324,081(2)
Reserve for uncollectible --------
accounts receivable $1,079,806 $960,000 $388,890 $1,492,616(3) $ 936,080
========== ======== ======== ========== ==========
Accumulated depreciation of
miscellaneous properties:
Rental water heater program $3,334,201 $352,547 - $ 257,804(4) $3,428,944
Other 41,052 27,101 - - 68,153
---------- -------- ---------- ----------
$3,375,253 $379,648 $ 257,804 $3,497,097
========== ======== ========== ==========
Reserve shown separately:
Injuries and damages reserve $ 242,901 - - $ 17,321(5) $ 225,580
========== ========== ==========
(1) Amount due from collection agency.
(2) Collections of accounts previously written off.
(3) Uncollectible accounts written off.
(4) Retirements of rental water heaters.
(5) Payments for construction accidents.
Schedule II
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(1) $1,286,799(2) $1,079,806
========== ========== ======== ========== ==========
Accumulated depreciation of
miscellaneous properties:
Rental water heater program $3,283,660 $ 350,642 - $ 300,101(3) $3,334,201
Other 135,354 27,958 - 280 683(4) 41,052
---------- ---------- ---------- ----------
$3,577,437 $ 378,600 $ 580,784 $3,375,253
========== ========== ========== ==========
Reserve shown separately:
Injuries and damages reserve $ 268,077 - - $ 25,176 (5) $ 242,901
========== ========== ==========
(1) Collection of accounts previously written off.
(2) Uncollectible accounts written off.
(3) Retirements of rental water heaters.
(4) Retirement of non-utility property.
(5) Payments for construction accidents.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
CENTRAL VERMONT PUBLIC SERVICE
CORPORATION
By /s/ 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
By /s/ Frederick S. Potter
--------------------------------------
Frederick S. Potter, Vice President -
Finance and Administration and
Principal Financial Officer
By /s/ James M. Pennington
--------------------------------------
James M. Pennington, Controller
and Principal Accounting Officer
March 13, 1995
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 13, 1995 /s/ Frederic H. Bertrand
-----------------------------------------
Frederic H. Bertrand
Director
March 13, 1995 /s/ Robert P. Bliss, Jr.
-----------------------------------------
Robert P. Bliss, Jr.
Director
March 13, 1995 /s/ Elizabeth Coleman
-----------------------------------------
Elizabeth Coleman
Director
March 13, 1995 /s/
-----------------------------------------
Luther F. Hackett
Director
March 13, 1995 /s/ F. Ray Keyser, Jr.
-----------------------------------------
F. Ray Keyser, Jr.
Director
March 13, 1995 /s/ Mary Alice McKenzie
-----------------------------------------
Mary Alice McKenzie
Director
March 13, 1995 /s/ Gordon P. Mills
-----------------------------------------
Gordon P. Mills
Director
March 13, 1995 /s/ Preston Leete Smith
-----------------------------------------
Preston Leete Smith
Director
March 13, 1995 /s/ Robert D. Stout
-----------------------------------------
Robert D. Stout
Director
March 13, 1995 /s/ Thomas C. Webb
-----------------------------------------
Thomas C. Webb
Director