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UNITED STATES 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
For the fiscal year ended December 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-8222
Central Vermont Public Service Corporation
(Exact name of registrant as specified in its charter)
Vermont 03-0111290
(State or other jurisdiction (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 incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
Cover page
State the aggregate market value of the voting stock held by non-
affiliates of the registrant: $143,980,458 based upon the closing price as of
January 29, 1999 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, 1999, there were outstanding
11,461,131 shares of Common Stock, $6 Par Value.
DOCUMENTS INCORPORATED BY REFERENCE
The Company's Definitive Proxy Statement relating to its Annual Meeting
of Stockholders to be held on May 4, 1999, to be filed with the Securities and
Exchange Commission pursuant to Regulation 14A under
the Securities Act of 1934, is incorporated by reference in Items 10, 11, 12
and 13 of Part III of this Form 10-K.
Cover page continued
Form 10-K - 1998
TABLE OF CONTENTS
Page
PART I
Item 1. Business................................................ 2
Item 2. Properties.............................................. 20
Item 3. Legal Proceedings....................................... 21
Item 4. Submission of Matters to a Vote of Security Holders..... 21
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters.................................... 22
Item 6. Selected Financial Data................................. 23
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 24
Item 8. Financial Statements and Supplementary Data............. 46
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.................... 79
PART III
Item 10. Directors and Executive Officers of the Registrant...... 79
Item 11. Executive Compensation.................................. 79
Item 12. Security Ownership of Certain Beneficial Owners and
Management............................................. 79
Item 13. Certain Relationships and Related Transactions.......... 79
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K............................................ 80
Signatures........................................................ 102
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 139,543
customers in nearly three-quarters of the towns, villages and cities in
Vermont. This represents about 50% of the Vermont population. In addition,
the Company supplies electricity to one municipal, one rural cooperative, and
one private utility.
The Company's sales are derived from a diversified customer mix. The
Company's sales to residential, commercial and industrial customers accounted
for 59% of total MWH sales for the year 1998. Sales to the five largest
retail customers receiving electric service from the Company during the same
period aggregated about 5% of the Company's total electric revenues for the
year. The Company's requirements resale sales accounted for approximately 4%,
entitlement sales accounted for 9% and other resale sales which include
contract sales, opportunity sales, sales to NEPOOL and short-term system
capacity sales accounted for approximately 28% of total MWH sales for the year
1998.
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 10,390 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 1998. Sales to its five largest retail customers during the same
period aggregated about 21% of Connecticut Valley's total electric revenues
for the year 1998.
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 the Province of 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 also owns a real estate company, C.V. Realty, Inc. and one
wholly owned subsidiary created for the purpose of financing and constructing
a hydroelectric facility in Vermont. This hydroelectric facility, owned by
Central Vermont Public Service Corporation - East Barnet Hydroelectric, Inc.
became operational September 1, 1984 and has been leased and operated by the
Company since its in-service date.
In addition, the Company has a wholly owned non-utility subsidiary,
Catamount Investment Corporation, which was formed for the purpose of holding
the Company's subsidiaries that invest in unregulated business opportunities.
For additional information of the Company's unregulated activities, see
PART II, Item 8 herein.
For Financial Information About Segments for the last three fiscal years,
See Part II, Item 8, Note 16-Segment Reporting.
REGULATION AND COMPETITION
State Commissions.
The Company is subject to the regulatory authority of the Vermont Public
Service Board (PSB) with respect to rates, and the Company and VELCO are
subject to PSB jurisdiction respecting securities issues, construction of
major generation and transmission facilities and various other matters. The
Company is subject to the regulatory authority of the New Hampshire Public
Utilities Commission as to matters pertaining to construction and transfers of
utility property in New Hampshire. Additionally, the Public Utilities
Commission of Maine and the Connecticut Department of Public Utility Control
exercise limited jurisdiction over the Company based on its joint-ownership
interest as a tenant-in-common of Wyman #4, a 619 MW generating plant and
Millstone #3, an 1149 MW nuclear generating facility, respectively.
Connecticut Valley is subject to the regulatory authority of the
New Hampshire Public Utilities Commission (NHPUC) with respect to rates,
securities issues and various other matters.
Federal Power Act.
Certain phases of the businesses of the Company and VELCO, including
certain rates, are subject to the jurisdiction of the Federal Energy
Regulatory Commission (FERC) as follows: the Company as a licensee of
hydroelectric developments under PART I, and the Company and VELCO as
interstate public utilities under Parts II and III of the Federal Power Act,
as amended and supplemented by the National Energy Act.
The Company has licenses expiring at various times under PART I of the
Federal Power Act for twelve of its hydroelectric plants. The Company has
obtained an exemption from licensing for the Bradford and East Barnet
projects.
Public Utility Holding Company Act of 1935.
Although the Company, by reason of its ownership of a utility subsidiary,
is a holding company, as defined in the Public Utility Holding Company Act of
1935, it is presently exempt, pursuant to Rule 2, promulgated by the
Commission under said Act, from all the provisions of said Act except Section
9(a)(2) thereof relating to the acquisition of securities of public utility
affiliates.
Environmental Matters.
In recent years, public concern for the physical environment has resulted
in increased governmental regulation of environmental matters. The Company is
subject to these regulations in the licensing and operation of the
generation, transmission, and distribution facilities in which it has
interest, as well as the licensing and operation of the facilities in which it
is a co-licensee. These environmental regulations are administered by local,
state and Federal regulatory authorities and concern the impact of the
Company's generation, transmission, distribution, transportation and waste
handling facilities on air, water, land and aesthetic qualities.
The Company cannot presently forecast the costs or other effects which
environmental regulation may ultimately have upon its existing and proposed
facilities and operations. The Company believes that any such costs related
to its utility operations would be recoverable through the rate-making
process. For additional information relating to Electric Industry
Restructuring 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 Maine Yankee, Connecticut Yankee and Yankee
Atomic Nuclear Power plants.
Competition.
Competition now takes several forms. At the wholesale level, other
electric power providers compete as suppliers to resale customers. Another
competitive threat is the potential for customers to form municipally owned
utilities in the Company's service territory. At the retail level, customers
have long had energy options such as propane, natural gas or oil for heating,
cooling and water heating, and self-generation for larger customers. Changes
anticipated as a result of the National Energy Policy Act of 1992 and
potential future change in state regulatory policy may result in retail
customers being able to purchase electric power generated by competing
suppliers for delivery over the Company's transmission and distribution
facilities.
Pursuant to Vermont statutes (30 V.S.A. Section 249), the PSB has
established as the service area for the Company the area it now serves. Under
30 V.S.A. Section 251(b) no other company is legally entitled to serve any
retail customers in the Company's established service area except as described
below.
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 a Department retail
sales request, 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. Such sales have not been made in the Company's service area
since 1993.
In addition, Chapter 79 of Title 30 authorizes municipalities to acquire
the electric distribution facilities located within their boundaries. The
exercise of such authority is conditioned upon an affirmative three-fifths
vote of the legal voters in an election and upon the payment of just
compensation including severance damages. Just compensation is determined
either by negotiation between the municipality and the utility or, in the
event the parties fail to reach an agreement, by the Public Service Board
after a hearing. If either party is dissatisfied, the statute allows them to
appeal the Board's determination to the Vermont Supreme Court. Once the price
is determined, whether by agreement of the parties or by the PSB, a second
affirmative three-fifths vote of the legal voters is required.
There has been only one instance where Chapter 79 of Title 30 has been
invoked; the Town of Springfield acted to acquire the Company's distribution
facilities in that community pursuant to a vote in 1977. This action was
subsequently discontinued by agreement between Springfield and the Company in
1985.
In addition, in late 1994 the Select Board of the Town of Bennington
considered whether to publicly warn a vote to acquire the Company's facilities
located in Bennington pursuant to Chapter 79 of Title 30. By vote of the
Selectors taken on January 9, 1995, the Town decided not to pursue the vote at
this time.
In the summer of 1997, the City of Claremont (Claremont), New Hampshire
engaged a consulting firm to conduct a study to determine Claremont's options
under New Hampshire law including the possible municipalization of Connecticut
Valley's service area located within its jurisdiction. The City Council has
appropriated approximately $75,000 for purposes of the study which has been
completed. Claremont continues to consider the study, but has taken no action
on it.
No other municipality served by the Company, so far as is known to the
Company, has taken any formal steps in an attempt to establish a municipal
electric distribution system.
Competition in the energy services market exists between electricity and
fossil fuels. In the residential and small commercial sectors this
competition is primarily for electric space and water heating from propane and
oil dealers. Competitive issues are price, service, convenience, cleanliness
and safety.
In the large commercial and industrial sectors, cogeneration and self-
generation are the major competitive threats to electric sales. Competitive
risks in these market segments are primarily related to seasonal, one-shift
operations that can tolerate periodic power outages, and for industrial
customers with steady heat loads where the generator's waste heat can be used
in their manufacturing process. Competitive advantages for electricity in
those segments are the cost of back up power sources, space requirements,
noise problems, and maintenance requirements.
In Docket DE 94-163, Order No. 21,683 (reh'g denied, Order No. 21,776),
the New Hampshire Public Utilities Commission (NHPUC) ruled that Public
Service Company of New Hampshire's (PSNH) rights to its franchise territory
are not exclusive as a matter of law. Connecticut Valley was an intervenor in
that docket. PSNH appealed the NHPUC's decision to the State of New Hampshire
Supreme Court, and Connecticut Valley has filed a brief with the New Hampshire
Supreme Court in favor of PSNH's position. The New Hampshire Supreme Court
upheld the NHPUC's position, but did not rule on just compensation issues.
The NHPUC ordered the petitioner to seek a ruling from the FERC that its
proposed operations were not a "sham transaction." The petitioner failed to
seek such a ruling, therefore, the NHPUC closed this docket.
For a discussion relating to Electric Industry Restructuring in Vermont
and New Hampshire see PART II, Item 7 herein.
For a discussion relating to the Company's wholesale electric business
see Wholesale Rates below.
RATE DEVELOPMENTS
Vermont Retail Rates.
On September 22, 1997, the Company filed for a 6.6% or $15.4 million per
annum, general rate increase to become effective June 6, 1998 (Order
No. 6018).
Also on September 22, 1997, the Company filed a retail rate redesign
whose primary purpose was to eliminate seasonal rates. The Vermont Public
Service Board (PSB) has not yet acted on this request.
On June 12, 1998, the Company filed with the PSB a request for a 10.7%
retail rate increase ($24.9 million of annualized revenues) to become
effective March 1, 1999 to cover primarily the higher power costs that the
Company will incur under the Vermont Joint Owners contract with Hydro-Quebec.
In this proceeding the PSB delayed the examination of the prudence and used-
and-usefulness of the Hydro-Quebec Contract pending the Vermont Supreme
Court's decision in the appeal of Docket No. 6018. After extensive
negotiation, on October 28, 1998 the DPS filed a Memorandum of Understanding
(MOU) between it and the Company which proposed a resolution of the issues
other than power costs under the Hydro-Quebec Contract. The proposed
resolution included, among other provisions, a final determination of the
Company's rate request except for issues of prudence and used-and-usefulness
of the Hydro-Quebec Contract, and a temporary, pro forma Hydro-Quebec prudence
and used-and-usefulness disallowance modeled on the Hydro-Quebec disallowance
which the PSB applied to Green Mountain Power Corporation in its February 1998
rate order. To reflect both the final and the temporary cost of service
determinations, the MOU proposed a "temporary rate increase" of 4.7% or
$10.9 million on an annualized basis effective with service rendered
January 1, 1999. By order dated December 11, 1998, the PSB approved the MOU
in its entirety. For additional information regarding recent rate increase
requests see PART II, Item 7 "Rates and Regulation" and Item 8 "Retail Rates"
herein.
New Hampshire Retail Rates.
Connecticut Valley's retail rate tariffs, approved by the New Hampshire
Public Utilities Commission (NHPUC), contain a Fuel Adjustment Clause (FAC)
and a Purchased Power Cost Adjustment (PPCA). Under these clauses,
Connecticut Valley recovers its estimated annual costs for purchased energy
and capacity which are reconciled when actual data is available. On the basis
of estimates of costs for 1998 and reconciliations from 1997, the combined
1998 FAC and PPCA would have resulted in an increase in revenues of
approximately $2.1 million for 1998. Based on a motion by the City of
Claremont, an intervenor, the NHPUC, in its order dated December 31, 1997,
found that Connecticut Valley was imprudent not to have terminated its
wholesale power contract with the Company and froze Connecticut Valley's FAC
and PPCA rates. Subsequently, the NHPUC, in deference to a temporary
restraining order issued by a federal district court, allowed FAC and PPCA
rates effective May 1, 1998 that would make the Company whole for 1997
undercollections, the 1998 undercollections incurred through April 30, 1998,
and the increase in 1998 power costs.
On the basis of estimates of costs for 1999 and reconciliations from
1998, the combined 1999 FAC and PPCA rates would have resulted in a decrease
in revenues of approximately $2.3 million for 1999. The decrease was
primarily caused by the elimination of the various undercollections from prior
periods mentioned above. The City of Claremont filed a motion to determine
the prudence of the 1999 power costs. However, by agreement of the parties,
including the NHPUC, the hearing was limited to the mathematical calculation
of the FAC and PPCA. An NHPUC order allowed the decrease. See PART II,
Item 7 herein for additional information regarding New Hampshire Electric
Industry Restructuring and Item 8 Note 13 herein for information regarding
Retail Rates-New Hampshire.
Connecticut Valley's retail rate tariffs, approved by the NHPUC, also
provide for a Conservation and Load Management Percentage Adjustment (C&LMPA)
for residential and commercial/industrial customers in order to collect
forecast C&LM costs. The forecast costs are updated effective January 1 of
each year and are reconciled when actual data are available. In addition,
Connecticut Valley's earnings reflect the recovery of lost revenues related to
fixed costs which Connecticut Valley fails to otherwise recover as a result of
C&LM activities. The C&LMPA further provides for the future recovery of
shareholder incentives related to past C&LM activities.
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 1998, under long-term contracts with
these qualifying facilities, Connecticut Valley purchased 41,477 MWH, of which
38,283 MWH were purchased from Wheelabrator Claremont Company, L.P.,
(Wheelabrator) who owns a solid waste plant. Connecticut Valley had filed a
complaint with FERC stating its concern that Wheelabrator has not been a
qualifying facility since the plant began operation. On February 11, 1998,
the FERC issued an Order denying Connecticut Valley's request of a refund of
past purchased power costs and lower future costs. The Company filed a
request for rehearing with the FERC on March 13, 1998 which was denied.
Subsequently, Connecticut Valley appealed to the D.C. Circuit Court of Appeals
which has yet to result in a decision.
See PART II, Item 7 herein for detailed information regarding
New Hampshire Electric Industry Restructuring.
Wholesale Rates.
The Company sells firm power to Connecticut Valley under a wholesale rate
schedule based on forecast data for each calendar year which is reconciled to
actual data annually. The rate schedule provides for an automatic update of
annual rates, as well as a subsequent reconciliation to actual data. The
Company filed and the FERC approved (1) a revenue increase of $281,000 or 2.4%
for 1998 power costs., (2) a reconciliation of 1997 revenues to actual costs
which resulted in an additional billing of $379,000, including interest, and
(3) a revenue decrease of $226,000 or 1.9% for 1999 power costs. The NHPUC
order dated February 28, 1997 regarding New Hampshire Electric Industry
Restructuring ordered, among other things, Connecticut Valley to terminate the
wholesale rate schedule with the Company.
On June 25, 1997, the Company filed with the FERC an application for
recovery of stranded costs and a notice of cancellation of the rate schedule
under which the Company sells firm power to Connecticut Valley contingent upon
the recovery of stranded costs. The stranded cost obligation, expressed on a
net present value basis as of January 1, 1998, is $44,925,000, would be
authorized by the Company's open access Transmission Service Tariff No. 7, and
collected as a surcharge to the transmission charges of any customer that uses
the Company's transmission system to wheel power for ultimate delivery within
Connecticut Valley service area. The surcharge is expected to recover the
stranded costs over a ten-year period. By order dated December 18, 1997, the
FERC rejected the Company's filing on the grounds that the transmission tariff
was an inappropriate vehicle for recovery. Pursuant to the FERC request in
that order, the Company filed a letter stating its intention to refile the
stranded cost recovery as an exit fee to the rate schedule under which the
Company sells firm power to Connecticut Valley. The Company did so on
January 12, 1998. The FERC accepted the filing and bifurcated the proceeding,
first, to determine whether Connecticut Valley would become an unbundled
transmission customer of the Company and, second, to determine the Company's
expectation period for serving Connecticut Valley and the allowable amount of
the exit fee.
On April 28, 1998, the Company filed its case-in-chief before the FERC
updating the amount of the exit fee to $54.9 million which was subsequently
amended to $50.0 million in a lump sum, describing all of the ways Connecticut
Valley will become an unbundled transmission customer of the Company
subsequent to termination, and establishing the expected period of service
based upon the date of termination, whenever that occurs, and the weighted
average service life of its commitments to power resources to serve
Connecticut Valley. Had termination taken effect on January 1, 1998 this
expectation period would have equaled nineteen years.
For additional information regarding legal and regulatory proceedings,
see PART II, Item 7, Electric Industry Restructuring and Item 8, Note 13,
Retail Rates.
On March 1, 1995, the Company filed a comprehensive, open access
transmission tariff (Tariff) with the FERC. The Tariff is designed to provide
firm and non-firm network transmission service, as well as firm point-to-point
service over the transmission systems of the Company and Connecticut Valley.
In addition, the Tariff would permit customers to make use of the Company's
contract rights to the transmission facilities of the Vermont Electric Power
Company, Inc. and New England Power Company. The Tariff would provide
transmission service that is comparable to that provided to native load
customers. Charges for such service would be based upon the Company's cost of
service for transmission.
The Company prepared and filed the Tariff in anticipation of developing
business opportunities in the area of electric transmission service. In
addition, recent FERC orders led the Company to believe that all electric
utilities owning transmission facilities would be required to prepare and file
such a Tariff in the near future. FERC issued a Notice Of Proposed Rulemaking
(NOPR) dated March 29, 1995, promoting wholesale competition in the electric
utility industry. The Company's Tariff complies with many requirements
proposed by the FERC in its NOPR.
Nine parties intervened in the Company's Tariff filing. On April 28,
1995, the FERC issued a deficiency letter asking for more information in a
number of areas. The Company filed a timely response to the deficiency letter
on June 14, 1995. Three parties filed protests in response to the Company
filing, and one additional party filed a request for late intervention. The
FERC accepted the Tariff for filing on August 14, 1995, suspended it and set
it for hearing. The order allowed the Tariff to become effective August 15,
1995, subject to refund and subject to the outcome of the Open Access NOPR
proceeding. The New Hampshire Electric Cooperative began taking transmission
service under the Tariff as of its effective date.
The Company entered into negotiations with FERC Staff and intervenors and
reached a settlement in principle in January 1996 on all rate issues contained
in the Tariff filing but one which was settled in August 1996. The settlement
provided for a fixed rate effective from August 15, 1995 through July 8, 1996.
The FERC has not taken action on the settlement.
On July 9, 1996 the Tariff was replaced by a pro forma transmission
tariff (Transmission Tariff) filed by the Company pursuant to FERC Order No.
888. The Transmission Tariff, which was approved by the FERC, embodied not
only the open access principles set forth in the FERC pro forma transmission
tariff, but also continued to embody the ratemaking and other Vermont and New
England specific non-rate terms and conditions. The Company has made a number
of filings to modify the Transmission Tariff in response to FERC orders
related to transmission tariffs of other utilities. All FERC orders received
have approved such modifications.
POWER RESOURCES
Overview.
The Company's and Connecticut Valley's energy generation and purchased
power required to serve their retail and firm wholesale customers was
2,488,581 MWH for the year ended December 31, 1998. The maximum one-hour
integrated demand during that period was 420.6 MW, which occurred on
December 30, 1998. The Company's and Connecticut Valley's total energy
generation and purchased power in 1998, including that related to all resale
customers, was 3,829,373 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, 1998 and at the time of the Company's own peak. For additional
information related to purchased power costs, refer to PART II, Item 7 herein.
Year Ended December 31, 1998
Net 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....................... 40.7 221,763 5.8 17.9 4.3
Diesel and Gas Turbine..... 28.9 1,258 - - -
JOINTLY OWNED PLANTS:
Millstone #3................ 8.2 59,291 1.6 - -
Wyman #4.................... 10.9 19,126 0.5 9.1 2.2
McNeil...................... 10.5 31,396 0.8 10.1 2.4
EQUITY OWNERSHIP IN PLANTS:
(Purchased)
Vermont Yankee.............. 158.7 1,045,930 27.3 137.6 32.7
MAJOR LONG-TERM PURCHASES:
Hydro-Quebec................ 195.3 1,073,448 28.0 161.4 38.4
Merrimack #2................ 15.7 73,116 1.9 - -
OTHER PURCHASES:
System and other purchases.. 127.4 396,279 10.4 173.2 41.2
Small power producers....... 33.7 212,645 5.6 17.7 4.2
Unit purchases.............. 55.4 237,378 6.2 59.8 14.2
Entitlement purchases....... 21.4 92,503 2.4 40.4 9.6
Pumped storage hydro........ 2.8 1,328 - - -
NEPEX......................... - 363,912 9.5 52.3 12.4
NET WHOLESALE SALES and
miscellaneous at time of peak - - - (258.9) (61.6)
_____ _________ _____ _____ _____
TOTAL.................... 709.6 3,829,373 100.0 420.6 100.0
===== ========= ===== ===== =====
Wholly Owned Plants.
The Company owns and operates 20 hydroelectric generating
facilities in Vermont which have an aggregate nameplate capability
of 41.2 MW and two gas-fired and one diesel-peaking units with 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 1998
Fuel MW Generation Load Net Plant
Name Location Type Ownership Entitlement MWH Factor Investment
Millstone #3 Waterford, Nuclear 1.73% 20 59,291 34%
$51,713,362
Connecticut
Wyman #4 Yarmouth, Oil 1.78% 11 19,126 20% $
1,380,143
Maine
Joseph C. McNeil Burlington, Various 20.00% 10.6 31,396 34% $
7,625,528
Vermont
Highgate Trans- Highgate Springs, 47.35% N/A N/A N/A $
9,161,002
mission Facility Vermont
The Company receives its share of the output and capacity of
Millstone
Unit #3 (Unit #3), an 1149 MW nuclear generating facility (see discussion
below); Wyman #4, a 619 MW generating facility and Joseph C. McNeil, a 53 MW
generating facility.
The Highgate Convertor, a 225 MW facility is directly connected to the
Hydro-Quebec System to the north of the Convertor and to the VELCO System for
delivery of power to Vermont Utilities. This facility can deliver power
either direction, but normally delivers power from Hydro-Quebec to Vermont.
The Company is responsible for its share of the operating expenses of
these facilities.
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 3.9% of its
entitlement. The Company's current equity ownership and net entitlement
percentages are 31.3 and 31.1, 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 about 160 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)
1994......................... 98.2 95.8
1995......................... 86.3 84.8
1996......................... 84.5 82.8
1997......................... 95.4 93.3
1998......................... 76.4 73.5
Vermont Yankee was shut down for scheduled refueling outages in 1993,
1995, 1996, and 1998.
As described in the overview section above, the Company is also 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) (See Note 4)
Connecticut Yankee............ (See Note 4) (See Note 4)
Yankee Atomic................. (See Note 4) (See Note 4)
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 PART II, Item 8 herein.
_______________
Notes:
(1) Currently, the Company resells at cost, through VELCO, about 20 MW of its
original entitlement to other Vermont utilities.
(2) "Availability Factor" means the hours that the plant is capable of
producing electricity divided by the total hours in the period.
(3) "Capacity Factor" means the total net electrical generation divided by
the product of the maximum design electrical rating capacity of 514 through
April 30, 1995 and 522 effective May 1, 1995, multiplied by the total hours in
the period.
(4) Maine Yankee, Connecticut Yankee and Yankee Atomic permanently ceased
power operations of their Nuclear Power Plants. See Decommissioning Expense
discussion below.
Decommissioning Expense.
Each of the Yankee companies and Unit #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 Unit #3 are included in
depreciation expenses.
The Company's entitlement percentage of decommissioning costs for Vermont
Yankee, Maine Yankee, Connecticut Yankee, Yankee Atomic and Unit #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 $66.7
Maine Yankee 1998 $343.9 $6.9 $4.3
Connecticut Yankee 1996 $426.7 $8.5 $5.0
Yankee Atomic 1991 $370.0 $13.0 $4.8
Millstone Unit #3 1997 $559.6 $9.7 $3.2
Vermont Yankee is in the process of preparing an updated site
decommissioning cost study. Preliminary results indicate that the new
decommissioning estimate could exceed $500 million in 1998 dollars. Vermont
Yankee expects to file results of the new decommissioning study with the FERC
during the first quarter of 1999, and expects that any resulting change in
rates will be effective January 1, 2000.
The Design Basis Documentation project (Project) initiated by Vermont
Yankee during 1996 is expected to be complete by the end of year 2000. The
Company's 35% share of the total cost for this Project is expected to be about
$6.2 million. Such costs will be deferred by Vermont Yankee and amortized
over the remaining license life of the plant.
On February 25, 1999, the Board of Directors of Vermont Yankee granted an
exclusive right to AmerGen Energy Company to conduct due diligence and
negotiate a possible agreement to purchase the assets of Vermont Yankee.
The Company owns interests in two of the five nuclear plants operated by
Northeast Utilities (NU): 1) a 2% equity interest in the Connecticut Yankee
Atomic Power Company (Haddam Neck Plant), and 2) a 1.7303% joint-ownership
interest in the Unit #3 of the Millstone Nuclear Power Station.
Millstone Unit #3 (Unit #3) received approval from the Nuclear Regulatory
Commission (NRC) commissioners and NRC staff on June 15, 1998 and June 29,
1998, respectively, to restart Unit #3 which was shut down on March 30, 1996,
due to numerous technical and non-technical problems. Unit #3 reached full
power operation on July 14, 1998. The Company's share of the total
incremental operating and maintenance costs for Unit #3 is estimated to be
$1.1 million, $2.6 million and $.9 million for 1996, 1997 and 1998,
respectively. The Company's share of incremental replacement power costs is
estimated to be $2.8 million, $3.5 million and $3.2 million for 1996, 1997 and
1998, respectively.
The Company remains actively involved with the other non-operating
minority joint-owners of Unit #3. This group is engaged in various activities
to monitor and evaluate NU's and Northeast Utilities Service Co.'s efforts
relating to Unit #3. On August 7, 1997, the Company and eight other non-
operating owners of Unit #3 filed a demand for arbitration with Connecticut
Light and Power Company and Western Massachusetts Electric Company and
lawsuits against NU and its trustees. The arbitration and lawsuits seek to
recover costs associated with replacement power, operation and maintenance
costs and other costs resulting from the shutdown of Unit #3. The non-
operating owners claim that NU and two of its wholly owned subsidiaries failed
to comply with NRC's regulations, failed to operate the facility in accordance
with good operating practice and attempted to conceal their activities from
the non-operating owners and the NRC.
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 PART II, Item 8 for information regarding the
premature shutdown of the Maine Yankee, Connecticut Yankee and Yankee Atomic
nuclear power plants.
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 several "requirements based" contracts for the four
components (uranium, conversion, enrichment and fabrication) used to produce
nuclear fuel. These contracts are executed only if the need or requirement
for fuel arises. Under these contracts, any disruption of operating activity
would allow Vermont Yankee to cancel or postpone deliveries until actually
required. The contracts extend through various time periods and contain
clauses to allow the option to extend the agreements. Negotiation of new
contracts or renegotiation of existing contracts routinely occurs, often
focusing on one of the four components at a time. The price of the 1998
refueling was approximately $22 million and the 1999 refueling will also cost
approximately $22 million. Future refueling costs will depend on market and
contract prices.
On January 20, 1997, Vermont Yankee entered into an agreement with a
former uranium supplier whereby the supplier could opt to terminate a
production purchase agreement dated August 4, 1978. Although there had been
no transactions under the production purchase agreement for several years,
Vermont Yankee maintained certain financial rights. In consideration for the
option to terminate the production purchase agreement and the subsequent
exercise of the option, Vermont Yankee received $0.6 million in 1997 which was
recorded as an offset to nuclear fuel expense. The potential future payments
that Vermont Yankee could receive over a ten year period, range from
$0.0 million to $2.4 million. No payments were received in 1998 by Vermont
Yankee under this agreement. Due to the uncertainty of this transaction, the
potential benefits will be recorded on a cash basis.
Under the Nuclear Waste Policy Act of 1982, the United States Department
of Energy (DOE) is responsible for the selection and development of
repositories for and the disposal of spent nuclear fuel and high-level
radioactive waste. Vermont Yankee, as required by that Act, has signed a
contract with the DOE to provide for the disposal of spent nuclear fuel and
high-level radioactive waste from its nuclear generation station beginning no
later than January 31, 1998; however, this delivery schedule has not been met
and is expected to be delayed significantly. It is not certain when the DOE
will accept spent nuclear fuel and high-level radioactive waste from Vermont
Yankee and other owners of nuclear power plants. Continued delays or a
default by the DOE would lead to consideration of costly alternatives
involving significant siting and environmental issues.
The DOE contract obligates Vermont Yankee to pay a one-time fee of
approximately $39.3 million for disposal costs for all spent fuel discharged
through April 6, 1983, and a fee payable quarterly equal to one mill per
kilowatt-hour of nuclear generated and sold electricity after April 6, 1983.
Although the $39.3 million for the one-time fee has been collected from the
Sponsors in rates, Vermont Yankee has elected to defer payment to the DOE as
permitted by the DOE contract. The fee plus accrued interest must be paid no
later than the first delivery of spent fuel to the DOE repository. Interest
accrues on the unpaid obligation based on the thirteen-week Treasury Bill rate
and is compounded quarterly. Through 1998, Vermont Yankee accumulated
$98.1 million in an irrevocable trust to be used exclusively for defeasing
this obligation ($103.8 million including accrued interest) at some future
date, provided the DOE complies with the terms of the aforementioned contract.
Vermont Yankee has primary responsibliity for the interim storage of its
spent nuclear fuel. The plant is currently able to operate with the ability
to discharge the entire reactor core to the spent fuel storage pool through
the 2001 refueling outage. Full core discharge capability through year 2008
refueling outage could be achieved with the installation of additional storage
racks in the spent fuel pool, subject to an NRC license amendment. A request
for this amendment was submitted in September 1998. Vermont Yankee is
investigating other options for additional storage capacity beyond the year
2001.
In November 1997, the U.S. District Court of Appeals for the D.C. Circuit
ruled that the lack of an interim storage facility does not excuse the DOE
from meeting its contract obligation to begin accepting spent nuclear fuel no
later than January 31, 1998. The ruling said, however, that the 1982 federal
law could not require the DOE to accept waste when it did not have a suitable
storage facility. The court directed the plaintiffs to pursue relief under
terms of their contracts with the DOE. Based on this ruling, since the DOE
did not take the spent nuclear fuel as scheduled, it may have to pay contract
damages.
In May 1998, the same court denied petitions from 60 states and state
agencies and 41 utilities, including Vermont Yankee, asking the court to
compel the DOE to submit a program, beginning immediately, for disposing of
spent nuclear fuel. The petitions were filed after the DOE defaulted on its
January 31, 1998 obligation to begin accepting the fuel. The court directed
Vermont Yankee and other plaintiffs to pursue relief under the terms of their
contracts with the DOE.
In a petition filed in August 1998, the court's May 1998 decision was
appealed to the U.S. Supreme Court. In November 1998, the Supreme Court
declined to review the lower court ruling that said utilities should go to
court and seek monetary damages from the DOE. In December 1998, the U.S.
Court of Claims ruled that three petitioning companies were entitled to
monetary damages from the DOE for failure to perform under the standard
contract. Although the Court did not award specific damages, leaving this for
subsequent litigation, it did establish the DOE's responsibility and liability
for spent fuel. The ultimate outcome of this legal proceeding is uncertain at
this time.
The average energy and capacity costs to the Company of energy generated
at the Vermont Yankee plant was 3.77, 4.68, 4.78, 4.06 and 5.81 cents per KWH
for the years 1994 through 1998, 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 $9.8 billion. Beyond that a licensee
maintains an indemnity agreement with the NRC, but subject to Congressional
approval. The first $200 million of liability coverage is the maximum
provided by private insurance. The Secondary Financial Protection Program is
a retrospective insurance plan providing additional coverage up to
$9.6 billion per incident by assessing $88.1 million against each of the
109 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 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 $3.7 million of such maximum assessment per incident per
year.
Major long-term purchases.
Canadian Purchases - Under various contracts, the Company purchases from
Hydro-Quebec capacity and associated energy. Under the terms of these
contracts, the Company is required to pay certain fixed capacity costs whether
or not energy purchases above a minimum level described in the contracts are
made. Such minimum energy purchases must be made whether or not other less
expensive energy sources might be available.
The company will receive varying amounts of capacity and energy from
Hydro-Quebec under the Vermont Joint Owners (VJO) contract during the 1999 to
2016 period. Related contracts were negotiated between the Company and
Hydro-Quebec which in effect alter the terms and conditions contained in the VJO
contract, reducing the overall power requirements and cost of the original
contract.
The average annual amount of capacity that the Company will purchase
through October 31, 2016 is 132 MW. The total commitment to purchase power
under these contracts on a nominal basis is approximately $1.0 billion net of
power sellbacks over the contract term. In February 1996, the Company reached
an agreement with Hydro-Quebec which lowered the 1997 cost of power by
approximately $5.8 million. As part of this agreement, the Company delivers
to NEPOOL under existing firm energy contracts or joint marketing activities
54 MW of Phase II transmission capacity for a five-year period which began
July 1, 1996 through June 30, 2001.
In the early phase of the VJO contract, two sellback contracts were
negotiated, the first delaying the purchase of about 25 MW of capacity and
associated energy, the second reducing the net purchase of Hydro-Quebec power.
In 1994, the company negotiated a third sellback arrangement whereby the
Company receives an effective discount on up to 70 MW of capacity starting in
November 1995 for the 1996 contract year (declining to 30 MW in the 1999
contract year). In exchange for this sellback, Hydro-Quebec has the right to
reduce capacity deliveries by up to 50 MW beginning as early as 2004 until
2015, including the use of a like amount of the Company's
Phase I/II facility rights and the ability to reduce the amounts of energy
delivered during a five-year term beginning in 2000.
There are specific contractual step up provisions that provide that in
the event any VJO member fails to meet its obligation under the contract with
Hydro-Quebec, the balance of the VJO participants, including the Company, will
"step up" to the defaulting party's share on a pro-rata basis. As of
December 31, 1998 the Company's VJO obligation is approximately 46% or
$1.0 billion on a nominal basis over the contract ending in 2016. The total
VJO contract obligation on a nominal basis over the term of the contract is
approximately $2.3 billion.
During January 1998, a significant ice storm affected parts of New
England and the Province of Quebec, Canada. This storm damaged major
components of the Hydro-Quebec transmission system over which power is
supplied to Vermont under the VJO contract with Hydro-Quebec. This resulted
in an interruption of a significant portion of scheduled contractual power
deliveries into Vermont. The ice storm's effect on Hydro-Quebec's
transmission system caused the VJO to examine Hydro-Quebec's overall
reliability and ability to deliver energy in the future. That review has
prompted the VJO to initiate an arbitration proceeding, the end result of
which may be the termination of the Contract. By way of the arbitration, the
VJO is also seeking to recover capacity payments made during the period of
non-delivery.
Through Velco, the Company purchased power from Merrimack #2, a coal-
fired generating plant owned by Northeast Utilities (NU), under a thirty-year
contract which expired April 30, 1998. Under this contract the Company was
obligated to make capacity payments which amounted to approximately
$4.6 million, $4.5 million and $1.8 million for 1996 through 1998,
respectively. Pursuant to the contract, as amended, Velco agreed to reimburse
PSNH, in the proportion which the Velco quota bears to the demonstrated net
capability of the plant, for all fixed costs of the unit and operating costs
of the plant incurred by PSNH, which were reasonable and cost-effective for
the remaining term of the Velco contract. In early 1998, PSNH took the
Merrimack Unit #2 facility off line, shut it down and commenced a maintenance
outage. In February, March and April of 1998, PSNH billed Velco for costs to
complete the maintenance outage. Velco disputes the validity of a portion of
the charges on grounds that the maintenance performed at the unit was to
extend the life of the Merrimack plant beyond the term of the Velco contract
and that the charges in connection with said investments were not reasonable
and cost-effective for the remaining term of the Velco contract. The Company
estimates the portion of the disputed charges allocable to the Company could
be as much as $1.0 million on a pre-tax basis.
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, 1998, the Company received 212,702 MWH from these sources for
which it paid $22,557,152.
The Company, through VELCO, is a participant in NEPOOL, which has been
open to all investor-owned, municipal, and cooperative utilities in New
England under an agreement in effect since 1971 and amended from time to time.
The Restated NEPOOL Agreement offers membership privileges to any entity
which is engaged or proposes to engage in the wholesale or retail electric
power business in New England. NEPOOL's function has changed in response to
the growing climate of competition and the FERC requirements for open access
transmission across systems. A new organization, an Independent System
Operator (ISO), has been formed to operate the bulk power generation and
transmission systems, to administer the regions open access transmission
tariff, and to operate the electric ISO wholesale power market for New
England. The bilateral market for transactions directly between NEPOOL
participants will continue as an alternative to the ISO wholesale spot market.
The ISO is governed by the principles put forth in the FERC Order 888
under rules defined by NEPOOL and approved by FERC. They include: to provide
independent, open and fair access to the regional transmission system, to
establish a non-discriminatory governance structure, to facilitate market-
based wholesale electric transactions, and to ensure the efficient management
and reliable operation of the regional bulk power system.
The ISO has established a bidding system for the newly defined generation
products; it will form the basis for the ISO's economic dispatch (based on bid
prices) of the generation products. This system provides a settlement
mechanism which will price the residual of a given generation product that is
excess to a participant's own needs, and is offered to the ISO wholesale power
market. A participant will pay as before the actual costs for its generation
products used to serve its load or takes to market. A participant will submit
a bid for its generation products to the ISO, and if the bid is accepted and
if the participant supplies residual generation products to the ISO wholesale
market, the participant will receive the market clearing price based on the
highest bids accepted for the residual product. If a participant needs to
purchase from the ISO wholesale market to serve its load, those purchases will
be made at market clearing price.
The ISO will also provide the main market place for participants to
secure open access transmission for transactions delivered on the Pool
Transmission Facilities (PTF). Over the next several years, the pricing
differences that had existed between transmission systems within NEPOOL will
disappear as a NEPOOL-wide transmission pricing arrangement for all PTF and
the open access tariffs of local network providers will offer access to all
other transmission facilities.
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 1998 occurred on December 30 and equaled 420.6 MW. At the time of this
peak, the Company had a reserve margin of 34%. NEPOOL's peak for the year
occurred on July 22, 1998 and totaled 21,406 MW. NEPOOL had an 11% reserve
margin at the time of its 1998 peak.
Power Resources - Future.
The Company has generally sufficient power under contract to supply its
current franchise obligations for the near-term prior to any advent of Retail
Wheeling. In addition, the Company will continue to utilize cost effective
demand side management programs where appropriate. The Company expects to
actively manage this portfolio of supply and demand side resources over the
near-term, as it has in the past, to minimize net power costs for its
ratepayers and shareholders. It is unclear what the Company's load
responsibilities will be upon the advent of Retail Wheeling. The certainty,
timing and nature of these events will be largely determined by legislative
and regulatory actions at the state and national levels.
TRANSMISSION
Vermont Electric Power Company, Inc.
VELCO engages in the operation of a high-voltage transmission system
which interconnects the electric utilities in the State including the areas
served by the Company. VELCO is also engaged in the business of purchasing
bulk power for resale, at cost, to the Company and the other electric
utilities (cooperative, municipal and investor-owned) in Vermont (the "Vermont
utilities") and transmitting such power for the Vermont utilities. Refer to
Item 8 herein for a discussion of the 1985 Four Party Agreement between the
Company, VELCO and two other major distribution companies in Vermont.
VELCO provides transmission services for the State of Vermont, acting by
and through the Department, and for all of the electric distribution utilities
in the State of Vermont. VELCO is reimbursed for its costs (as defined in the
agreements relating thereto) for the transmission of power for such entities.
The Company, as the largest electric distribution utility in Vermont, is the
major user of VELCO's transmission system.
The Company owns 34,083 shares (56.8%) of the Class B common stock of
VELCO, the balance being owned by other Vermont utilities. Each share of
Class B common stock has one vote. The Company also owns 46,624 shares
(46.6%) of the Class C preferred stock of VELCO, the balance being owned
by other Vermont utilities. Shares of Class C preferred stock have no voting
rights except the limited right to vote VELCO's shares of common stock in
Vermont Electric Transmission Company, Inc. (VETCO) if certain dividend
requirements are not met.
NEPOOL Arrangements.
VELCO participates for itself and as agent for the Company and twenty-one
other Vermont utilities in NEPOOL.
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, 1998 and
125,000 shares of Class C preferred stock, of which 100,000 shares were
outstanding at December 31, 1998. On that date there were authorized and
outstanding three issues of First Mortgage Bonds, aggregating $33,078,000,
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
1999 to transmit power to Vermont utilities. The costs of such facilities are
presently estimated at $4,062,745 including allowance for funds used during
construction calculated at a rate of approximately 6.5%. For a description of
VELCO's properties, see "VELCO" under Item 2.
Management.
In 1957 VELCO entered into an agreement (the "Three-Party Agreement")
whereby the Company and Green Mountain agreed that, if VELCO transmits firm
power it owns (which VELCO does not now do), VELCO would have the right to
purchase all such firm power not sold to others. As such, VELCO would have
the obligation to pay associated 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 Power Corporation entered
into a Three-Party Transmission Agreement, dated November 21, 1969, as
amended, whereby they have agreed to pay transmission charges thereon in an
aggregate amount sufficient, with VELCO's other revenues, to pay all of
VELCO's expenses including capital costs. VELCO's Bonds are secured by a
first mortgage on the major part of VELCO's transmission properties and by the
assignment to the Trustee of the Three-Party Agreement, the Three-Party
Transmission Agreement and certain other contracts as specified in the VELCO
Indenture. See Item 8 herein for information relating to the 1985 Four-Party
Agreement.
Vermont Electric Transmission Company, Inc.
In connection with the importing of Canadian power, VELCO has created a
wholly owned subsidiary, VETCO, to construct, finance, own and operate the
Vermont portion of the transmission line which connects the Hydro-Quebec lines
at the Canadian border to the lines of New England Electric Transmission
Corporation, a subsidiary of New England Electric System, at the New Hampshire
border on the Connecticut River. VETCO entered into a Capital Funds Agreement
with VELCO pursuant to which VETCO may request up to $12,500,000 (of which
$10,000,000 was contributed as of December 31, 1998) of capital contributions
from VELCO and has entered into Transmission Line Support Agreements with 20
New England utilities, including VELCO as representative for 14 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. Pursuant to a
Vermont Participation Agreement and a Capital Funds Support Agreement with
Velco and 14 Vermont electric distribution utilities, including the Company,
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, 1998 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 4.56% of
Phase I Hydro-Quebec capital costs over a 20 year recovery period through and
including 2006. The Company also participated in the construction of Phase II
Hydro-Quebec transmission facilities which began operation in November 1990.
This service increased the maximum capacity of the Hydro-Quebec 450 KV DC line
from 690 MW to 2000 MW and extended 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 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 Management 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.
The Company provides information to customers to help them use
electricity more efficiently, first by ensuring that the customers are on the
correct rate and have incorporated efficiency and conservation measures;
secondly, by continually evaluating new energy management systems and other
technologies to identify and develop programs to address new market
opportunities and the competitive strengths of electricity.
DIVERSIFICATION
See PART II, Items 7 and 8 herein for information regarding the Company's
diversification activities.
The Company is continually assessing additional diversification
opportunities. Any new investments will be financed primarily through a
combination of debt and equity.
EMPLOYEE INFORMATION
A Local Union No. 300 affiliated with the International Brotherhood of
Electrical Workers represents operating and maintenance employees of the
Company and its wholly owned subsidiaries. At December 31, 1998 the Company
and its wholly owned subsidiaries employed 532 persons, of which 209 are
represented by the union. On December 30, 1998, the Company and its employees
represented by the union agreed to a three-year contract, which expires on
December 31, 2001. The new contract provides for a general wage increase of
2.6% effective January 1, 1999, January 2, 2000 and December 31, 2000. Under
the terms of the new agreement, Company's employees represented by the union
will contribute weekly pre-tax premiums for medical coverage of eight, nine
and ten dollars effective July 1, 1999, January 1, 2000 and January 1, 2001,
respectively.
SEASONAL NATURE OF BUSINESS
The Company experiences its heaviest loads in the colder months of the
year. Winter recreational activities, longer hours of darkness and heating
loads from cold weather usually cause the Company's peak of electric MWH sales
to occur in January or late December. For additional information regarding
the seasonal nature of business see PART II, Item 8 herein.
OFFICERS
The following sets forth the Executive Officers of the Company. There
are no family relationships among the executive officers.
Executive Officers of the Registrant:
Name and Age Office Officer Since
Robert H. Young, 51 President and Chief
Executive Officer 1987
Francis J. Boyle, 53 Senior Vice President, Chief
Financial Officer and Treasurer 1995
Kent R. Brown, 53 Senior Vice President-Engineering
and Operations 1996
William J. Deehan, 46 Vice President-Regulatory Affairs
and Strategic Analysis 1991
Joan F. Gamble, 41 Assistant Vice President, Human
Resources and Strategic Planning 1998
Joseph M. Kraus, 43 Vice President, Secretary and
General Counsel 1987
James M. Pennington, 43 Vice President, Controller and
Principal Accounting Officer 1993
Robert E. Rogan, 39 Vice President, Public Affairs 1998
Douglas D. Sinclair, 50 Vice President and General
Manager for Business Development 1997
L. Douglas Barba, 51 Senior Vice President and General
Manager - Catamount Energy
Corporation 1992
Mr. Young joined the Company in 1987. He was elected Director, President
and Chief Executive Officer in 1995. He was elected Senior Vice President -
Finance and Administration in 1988, and Executive Vice President and Chief
Operating Officer in 1993.
Mr. Boyle joined the Company in October, 1995, as Vice President -
Finance and Administration and Chief Financial Officer. From 1993 to 1995,
Mr. Boyle served as Chief Financial Officer of Westmoreland Coal Company
("Westmoreland") in Philadelphia, Pennsylvania. In November 1994,
Westmoreland and several of its subsidiaries commenced Chapter 11 proceedings
to confirm a so-called "prepackaged" plan of reorganization under which the
court was asked to approve a sale of assets, the proceeds of which were to be
used to satisfy in full certain maturing obligations of Westmoreland. In
December 1994, Westmoreland's plan of reorganization was confirmed, the asset
sale was consummated, the obligations in question were paid, and Westmoreland
emerged from Bankruptcy. On December 23, 1996, Westmoreland and four of its
subsidiaries commenced Chapter 11 proceedings. The Chapter 11 proceedings
were precipitated by large liabilities Westmoreland and four of its
subsidiaries have to retiree medical benefit plans for the benefit of retired
mine workers. From 1985 to 1992, Mr. Boyle was Chief Financial Officer of El
Paso Natural Gas Company, El Paso, Texas.
Mr. Brown joined the Company in September 1996. Prior to being elected
to his present position in 1997, he was elected as Vice President -
Engineering and Operations in 1996. From 1992 to 1995 he served as Chairman,
President and Chief Executive Officer of Kansas Gas and Electric Company
("KG&E") and Group Vice President of KG&E from 1982 to 1992.
Mr. Deehan joined the Company in 1985. Prior to being elected to his
present position in 1996, he was elected Assistant Vice President - Rates and
Economic Analysis in 1991.
Ms. Gamble joined the Company in 1989. Prior to being elected to her
present position in May 1998, she was Director of Marketing Research &
Planning from 1989 to 1996; Director of Strategic and Policy Planning from
1996 to September 1997 and Director of Human Resources and Strategic Planning
from September 1997 to May 1998.
Mr. Kraus joined the Company in 1981. Prior to being elected to his
present position in 1996, he was elected as Corporate Secretary and Senior
Corporate Counsel in 1987 and Corporate Secretary and General Counsel in 1994.
Mr. Pennington joined the Company in 1989. Prior to being elected to his
present position in 1997, he was elected Controller and named Principal
Accounting Officer in 1993.
Mr. Rogan joined the Company in 1998 as Vice President, Public Affairs.
Prior to joining the Company, he served as Deputy Chief of Staff for the
Governor of Vermont from 1994 to 1998. He served as Director of External
Affairs for the Agency of Health Care Administration in Florida from 1992 to
August 1994 and as Deputy Director and Lobbyist in the Florida Governor's
Washington office from 1991 to 1992.
Mr. Sinclair joined the Company in April 1997 as Vice President and
General Manager for Business Development. Prior to joining the company, from
1994 to 1996 he served as President and Chief Executive Officer at Noma
International. In 1991 he joined Novatel Communications, Ltd. as Chief
Financial Officer and was President and Chief Executive Officer of Novatel
Carcom, Inc. from 1992 to 1994.
Mr. Barba joined Catamount Energy Corporation, a subsidiary of Catamount
Investment Corporation (a wholly owned subsidiary of the Company), in August
1992 as Senior Vice President and General Manager.
The term of each officer is for one year or until a successor is elected.
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 23 small generating stations
with a total current nameplate capability of 70,070 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 and has a 47.35% joint-ownership interest in a transmission
interconnection with Hydro-Quebec in Vermont.
The electric transmission and distribution systems of the Company include
about 614 miles of overhead transmission lines, about 7,322 miles
of overhead distribution lines and about 257 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 430 miles of overhead distribution lines and
about 12 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 July 29, 1996, the Company filed a Declaratory Judgment action in the
United States District Court for the District of Vermont. The Complaint names
as defendants a number of insurance companies that issued policies to the
Company dating from the mid 1940s to the late 1980s. The Company asserted
that policies issued by defendants provide coverage for all defense and
remediation costs associated with the Cleveland Avenue property and other
sites. Settlement has been reached with all defendants. See PART II, Item 8
"Environmental" for related disclosures.
On August 7, 1997, the Company and eight other non-operating owners of
Unit #3 filed a demand for arbitration with Connecticut Light and Power
Company and Western Massachestts Electric Company and lawsuits against NU and
its trustees. The arbitration and lawsuits seek to recover costs associated
with replacement power, operation and maintenance costs and other costs
resulting from the shutdown of Unit #3. The non-operating owners claim that
NU and two of its wholly owned subsidiaries failed to comply with NRC's
regulations, failed to operate the facility in accordance with good operating
practice and attempted to conceal their activities from the non-operating
owners and the NRC.
Except as otherwise described under Management's Discussion and Analysis
of Financial Condition and Results of Operations, Item 7, 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 1998.
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. Newspaper listings of stock transactions
use the abbreviation CVtPS or CentlVtPS.
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
1998
First quarter.............. $ 15 7/16 $ 13 1/8
Second quarter............. 15 1/4 14 5/16
Third quarter.............. 14 15/16 9 3/4
Fourth quarter............. 11 1/2 9 3/4
1997
First quarter.............. $ 13 1/8 $ 10 3/8
Second quarter............. 11 3/8 10 3/8
Third quarter.............. 13 15/16 11
Fourth quarter............. 15 3/8 13
(b) As of December 31, 1998, there were 11,905 holders of the Company's
common stock, $6 par value.
(c) Common stock dividends have been declared quarterly. Cash dividends
of $.22 per share were paid for all quarters of 1997 and 1998.
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, 1998, the Common Stock Equity
of the unconsolidated Company was 61.4% 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)
1998 1997 1996 1995 1994
For the year
Operating revenues $303,835 $304,732 $290,801 $288,277 $277,158
Net income before extraordinary charge $ 3,983 $ 17,151 $ 19,442 $ 19,851 $ 14,800
Extraordinary charge net of taxes $ - $ 811 $ - $ - $ -
Net income $ 3,983 $ 16,340 $ 19,442 $ 19,851 $ 14,800
Earnings available for common stock $ 2,038 $ 14,312 $ 17,414 $ 17,823 $ 12,662
Consolidated return on average
common stock equity 1.1% 7.5% 9.4% 10.0% 7.2%
Earnings per basic and diluted share
of common stock before extraordinary
charge $.18 $1.32 $1.51 $1.53 $1.08
Earnings per basic and diluted share of
common stock $.18 $1.25 $1.51 $1.53 $1.08
Cash dividends paid per share of
common stock $.88 $.88 $.84 $.80 $1.42
Book value per share of common stock $15.63 $16.38 $16.19 $15.51 $14.56
Net cash provided by operating
activities $ 21,743 $ 41,974 $ 43,007 $ 42,583 $ 50,987
Dividends paid $ 12,006 $ 12,630 $ 11,728 $ 11,350 $ 18,845
Construction and plant expenditures $ 16,046 $ 13,841 $ 18,952 $ 21,337 $ 22,621
Conservation and load management
expenditures $ 2,208 $ 1,837 $ 1,589 $ 3,899 $ 6,159
At end of year
Long-term debt $ 90,077 $ 93,099 $117,374 $119,142 $120,157
Capital lease obligations $ 16,141 $ 17,223 $ 18,304 $ 19,385 $ 20,467
Redeemable preferred stock $ 18,000 $ 19,000 $ 20,000 $ 20,000 $ 20,000
Total capitalization
(excluding current portion
of debt) $311,454 $324,499 $350,201 $346,341 $339,462
Total assets $530,282 $531,940 $502,968 $489,213 $489,570
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
Earnings Overview.
The Company's 1998 net income was $4.0 million or $.18 per share of
common stock, which equates to a 1.1% return on average common equity. Net
income and earnings per share of common stock for 1998 compares to
$16.3 million and $1.25 in 1997, and $19.4 million and $1.51 in 1996. The
return on average common equity was 7.5% for 1997 and 9.4% for 1996.
For 1998, net income and earnings per share of common stock for the
Company's utility business reflects the negative impact of increased operating
costs, predominantly purchased power, and two regulatory actions. First,
during April 1998 the Company agreed to toll the statutory period of time in
which the Vermont Public Service Board (PSB) must act on its pending 6.6% rate
increase request filed in September 1997. At the same time, the Company asked
the Vermont Supreme Court to review the PSB's denial of the Company's claim
that the PSB is precluded from again trying the Company on certain Hydro-
Quebec contract and demand side management decisions. The appeal and
associated stay of the rate case significantly delayed the date that new rates
would have otherwise taken effect. As a result, the Company's earnings for
1998 were adversely affected. Second, because of the October 27, 1998 retail
rate increase settlement discussed below and in Note 13 to the Consolidated
Financial Statements, net income and earnings per share of common stock for
1998 include the negative impact of an after-tax disallowance of $4.3 million,
or $.38 per share of common stock for the Company's purchased power costs
under the Hydro-Quebec Contract.
Also, for 1998 net income and earnings per share of common stock for the
Company's utility business reflects the net effect at Connecticut Valley
Electric Company Inc. (Connecticut Valley) of charges taken during the fourth
quarter of 1998 of $3.7 million, or $.32 per share of common stock, offset by
the reversal of 1997 charges during the first quarter of 1998 of $4.5 million,
or $.39 per share of common stock. These charges and reversal of charges are
discussed below and in Notes 1 and 13 to the Consolidated Financial
Statements.
On June 12, 1998, the Company filed with the PSB a request for a 10.7%
rate increase ($24.7 million of annualized revenues) effective March 1, 1999.
On October 27, 1998, the Company reached an agreement with the Vermont
Department of Public Service (DPS) regarding this rate increase request.
The agreement, which was approved by the PSB on December 11, 1998,
provides for a temporary rate increase in the Company's Vermont retail rates
of 4.7% or $10.9 million on an annualized basis beginning with service
rendered January 1, 1999 and sets the Company's authorized return on common
equity in its Vermont retail business at 11%. The rate increase is temporary
insofar as it is subject to adjustment upon future resolution of the
Hydro-Quebec Contract issues presently before the Vermont Supreme Court (V.C.)
discussed in Note 13 to the Consolidated Financial Statements.
The Company filed for a 6.6% or $15.4 million general rate increase on
September 22, 1997 to become effective June 6, 1998, which is now stayed
pending a review by the V.C. as more fully discussed in Note 13 to the
Consolidated Financial Statements.
For 1997, net income and earnings per share of common stock for the
Company's utility business reflect a net of tax extraordinary charge of
approximately $.8 million and $.07, respectively, associated with the
discontinued application of Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation," applied
to Connecticut Valley. In Addition, Connecticut Valley incurred an after-tax
charge of $3.6 million and $.31 per share of common stock for disallowed power
costs.
For 1997, non-utility net income and earnings per share of common stock
reflect a gain of $1.8 million and $.16, respectively, from the sale by
Catamount of its 8.1% partnership's interest in the NW Energy Williams Lake
L.P. Project.
In addition, 1997 net income and earnings per share of common stock
reflected an after-tax gain of approximately $1.3 million and $.12,
respectively, from sale of non-utility property.
Results of Operations.
The major elements of the Consolidated Statement of Income are discussed
below.
Operating revenues and megawatt-hour (MWH) sales A summary of MWH sales and
operating revenues for 1998, 1997 and 1996 is set forth below:
MWH Sales Revenues (000's)
1998 1997 1996 1998 1997 1996
Residential 930,666 945,199 957,733 $115,911 $116,314 $108,603
Commercial 937,547 916,311 900,590 103,221 104,460 98,890
Industrial 418,778 427,764 401,781 33,617 34,206 32,399
Other retail 7,123 7,138 7,229 1,943 1,937 1,856
_________ _________ ________ ________ ________ ________
Total retail sales 2,294,114 2,296,412 2,267,333 254,692 256,917 241,748
_________ _________ ________ ________ ________ ________
Resale sales:
Firm 2,284 1,051 1,717 94 46 81
Entitlement 319,703 378,273 470,760 19,370 18,925 24,781
Other 1,008,635 827,818 770,542 26,861 22,265 18,705
_________ _________ ________ ________ ________ ________
Total resale sales 1,330,622 1,207,142 1,243,019 46,325 41,236 43,567
_________ _________ ________ ________ ________ ________
Other revenues - - - 2,818 6,579 5,486
_________ _________ _________ ________ ________ ________
Total 3,624,736 3,503,554 3,510,352 $303,835 $304,732 $290,801
========= ========= ========= ======== ======== ========
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. Compared to 1997, retail MWH sales for 1998 decreased 2,298 MWH
and related revenues decreased $2.2 million, or .9% compared to 1997. The
revenue decrease is primarily attributable to a modified rate design reflected
in bills rendered since April 1, 1997. The modified rate design, which is
revenue neutral on an annual basis, decreases prices charged during the winter
months of December through March and increases prices during the remaining
months of the year.
Retail MWH sales for 1997 increased 1.3% compared to 1996 reflecting an
improved Vermont economy. However, retail revenues increased $15.2 million or
6.3% over 1996 due to a $12.8 million increase in revenues resulting from the
full year impact of a 5.5% retail rate increase effective June 1, 1996, 2.0%
retail rate increase effective January 1, 1997, the positive impact of the
modified rate design described above, and a 1.3% increase in retail MWH sales.
For 1998, entitlement MWH sales decreased 15.5% compared to 1997. The
decrease results primarily from the scheduled refueling and maintenance outage
of the Vermont Yankee plant. The outage, which reduced the plant's 1998
output, also reduced MWH sales. However, a portion of the higher costs of the
Company's share of Vermont Yankee's costs associated with the refueling and
maintenance outage was passed on to entitlement customers resulting in an
increase in entitlement revenues of $.4 million, or 2.4%.
Entitlement MWH sales and revenues decreased for 1997 compared to 1996
primarily due to the scheduled termination of several sales agreements in late
1996.
Other resale sales increased 180,817 MWH and related revenues increased
$4.6 million for 1998. The increase resulted primarily from short-term
system capacity sales between the Company and Virginia Power which jointly
supply wholesale power in New England. This increase is partially offset by
lower sales to NEPOOL.
Other resale sales and revenues for 1997 increased 7.4% and 19.0%,
respectively, due to increased sales to New England Power Pool (NEPOOL)
partially offset by a decrease in wholly owned and jointly owned units sales.
Other revenues decreased for 1998 due to a provision for rate refunds of
$2.7 million related to a Fuel Adjustment Clause (FAC) and Purchased Power
Cost Adjustment (PPCA) associated with the December 3, 1998 Court of Appeals'
decision discussed below, and to lower revenues associated with transmission
interconnection agreements partially offset by increased pole attachment
rentals.
The increases in other revenues for 1997 resulted primarily from an
increase in transmission revenues related to various transmission
interconnection agreements.
The table below summarizes the components of increases or decreases in
revenues compared to the prior year (dollars in thousands):
1998 1997
Revenue increase (decrease) from:
Retail MWH sales $ (90) $ 2,377
Retail rates (2,135) 12,792
Changes in firm resale sales 48 (35)
Changes in entitlement sales 445 (5,856)
Changes in other resale sales 4,596 3,560
Changes in other revenues (3,761) 1,093
_______ _______
Net increase over prior year $ (897) $13,931
======= =======
Purchased power The Company purchases approximately 90% of its power needs
under several contracts of varying duration. Over 30% of its purchases are
from affiliated companies whereby the Company receives its entitlement share
of the output. The Company's purchased power portfolio assures that a
diversified mix of sources and fuel types are available to meet the Company's
long-term load growth while providing short and intermediate term
opportunities to purchase or sell capacity and energy to reduce overall power
costs. A breakdown of the Company's energy sources is shown below:
Year Ended December 31
1998 1997 1996
Nuclear generating companies 33% 36% 36%
Canadian imports 28 32 30
PSNH-coal 2 9 8
Company-owned hydro 6 5 6
Jointly owned units 3 1 2
Small power producers 6 6 6
Other sources 22 11 12
___ ___ ___
100% 100% 100%
=== === ===
The Company maintains a 1.7303% joint-ownership interest in Millstone
Unit #3 (Unit #3) of the Millstone Nuclear Power Station and owns a 2% equity
interest in Connecticut Yankee. These two plants are operated by Northeast
Utilities (NU). The Company also maintains joint-ownership interests in
Joseph C. McNeil, a 53 MW wood, gas and oil-fired unit and Wyman #4, a 619 MW
oil-fired unit and owns a 31.3%, 2% and 3.5% equity interest in Vermont
Yankee, Maine Yankee and Yankee Atomic, respectively. The Company's
entitlement percentage for Vermont Yankee is 35%. In addition, the Company
owns 20 hydroelectric generating units with 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.
Millstone Unit #3 (Unit #3) received approval by the Nuclear Regulatory
Commission (NRC) commissioners and NRC staff on June 15, 1998 and June 29,
1998, respectively, to restart Unit #3 which was shut down on March 30, 1996,
due to numerous technical and non-technical problems. Unit #3 reached full
power operation on July 14, 1998. The Company's share of incremental
operating and maintenance costs for Unit #3 is estimated to be $1.1 million ,
$2.6 million and $.9 million for 1996, 1997 and 1998, respectively. The
Company's share of incremental replacement power costs is estimated to be
$2.8 million, $3.5 million and $3.2 million for 1996, 1997 and 1998,
respectively.
The Company remains actively involved with the other non-operating
minority joint-owners of Unit #3. This group is engaged in various activities
to monitor and evaluate NU's and Northeast Utilities Service Co.'s efforts
relating to Unit #3. On August 7, 1997, the Company and eight other non-
operating owners of Unit #3 filed a demand for arbitration with Connecticut
Light and Power Company and Western Massachusetts Electric Company and
lawsuits against NU and its trustees. The arbitration and lawsuits seek to
recover costs associated with replacement power, operation and maintenance
costs and other costs resulting from the shutdown of Unit #3. The non-
operating owners claim that NU and two of its wholly owned subsidiaries failed
to comply with NRC's regulations, failed to operate the facility in accordance
with good operating practice and attempted to conceal their activities from
the non-operating owners and the NRC.
In 1992, 1996 and 1997, the Board of Directors of Yankee Atomic,
Connecticut Yankee and Maine Yankee, respectively, decided to permanently
discontinue operation of the Yankee Atomic, Connecticut Yankee and Maine
Yankee nuclear power plants, and to decommission the facilities. For
additional information in regard to the permanent shutdown of these nuclear
power plants see Note 2 to the Consolidated Financial Statements.
The Vermont Yankee nuclear power plant, which provides approximately
one-third of the Company's power supply, began a refueling outage on March 21,
1998 and returned to service on June 3, 1998. The refueling outage extended
twenty-six days beyond the scheduled forty-nine days. Vermont Yankee had no
scheduled refueling outage in 1997 and had a scheduled refueling outage from
September 7 through November 5, 1996.
The Design Basis Documentation project (Project) initiated by Vermont
Yankee during 1996 is expected to be complete by the end of year 2000. The
Company's 35% share of the total cost for this Project is expected to be about
$6.2 million. Such costs will be deferred by Vermont Yankee and amortized
over the remaining license life of the plant.
During scheduled nuclear refueling outages, the Company purchases more
costly replacement energy from other sources to satisfy energy needs. In
accordance with current rate-making treatment, the Company defers and
amortizes to expense over their respective fuel cycles the incremental
replacement energy and maintenance costs associated with refueling outages for
the Vermont Yankee nuclear power plant and Unit #3 jointly owned nuclear
generating unit. During 1998, the Company incurred $3.1 million and $6.5
million for replacement energy and maintenance costs, respectively, of which
$7.2 million in total was deferred. During 1996, the Company deferred $1.5
million and $6.0 million of replacement energy and maintenance costs,
respectively.
On February 25, 1999, the Board of Directors of Vermont Yankee granted an
exclusive right to AmerGen Energy Company to conduct due diligence and
negotiate a possible agreement to purchase the assets of Vermont Yankee.
Under a long-term purchase power contract expiring in 2016, the Company
receives varying amounts of capacity and energy from Hydro-Quebec. See Note
14 to the Consolidated Financial Statements for further details related to the
Hydro-Quebec power contracts.
Until its termination on April 30, 1998, the Company purchased power and
energy from Merrimack Unit #2 pursuant to a contract dated July 16, 1966
entered into by and between Vermont Electric Power Company, Inc. (Velco) and
Public Service Company of New Hampshire (PSNH). Pursuant to the contract, as
amended, Velco agreed to reimburse PSNH, in the proportion which the Velco
quota bears to the demonstrated net capability of the plant, for all fixed
costs of the unit and operating costs of the unit incurred by PSNH, which are
reasonable and cost-effective for the remaining term of the Velco contract.
In early 1998, PSNH took the Merrimack Unit #2 facility off line, shut it down
and commenced a maintenance outage. In February, March and April of 1998,
PSNH billed Velco for costs to complete the maintenance outage. Velco
disputes the validity of a portion of the charges on grounds that the
maintenance performed at the unit was to extend the life of the Merrimack
plant beyond the term of the Velco contract and that the charges in connection
with said investments were not reasonable and cost-effective for the remaining
term of the Velco contract. The Company estimates that the portion of the
disputed charges allocable to the Company could be as much as $1.0 million on
a pre-tax basis.
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
1998, the Company purchased 212,702 MWH of which 154,832 MWH is associated
with the Vermont Electric Power Producers and 38,283 MWH with a
New Hampshire/Vermont solid waste plant. The Company expects to purchase
approximately 203,000 MWH of small power output in each year 1999 through
2003. Based on the forecast level of production, the total commitment in the
next five years to purchase power from these qualifying facilities is
estimated to be $113.7 million.
The Company engages in purchases and sales with other electric utilities
and with NEPOOL to take advantage of immediate pricing and other market
conditions. The Company also engages in marketing activities with Virginia
Power which jointly supply wholesale power in New England. These purchases
are included in Other sources in the table above.
The net cost components of purchased power and production fuel costs for
the past three years were as follows (dollars in thousands):
1998 1997 1996
Units Amount Units Amount Units Amount
Purchased and produced:
Capacity (MW) 613 $104,740 527 $ 99,513 526 $ 86,431
Energy (MWH) 3,478,860 80,147 3,470,235 71,930 3,445,259 67,991
________ ________ ________
Total purchased power costs 184,887 171,443 154,422
Production fuel (MWH) 332,835 1,996 237,064 1,820 295,802 1,570
________ ________ ________
Total purchased power and
production fuel costs 186,883 173,263 155,992
Less entitlement and other
resale sales (MWH) 1,328,338 46,231 1,206,091 41,190 1,241,302 43,486
________ ________ ________
Net purchased power and
production fuel costs $140,652 $132,073 $112,506
======== ======== ========
For 1998, purchased capacity cost increased $5.2 million over 1997. This
increase is the result of a $7.4 million disallowance of Hydro-Quebec power
costs discussed below, $7.2 million of higher costs primarily associated with
the Hydro-Quebec contract, the Vermont Yankee extended outage and $1.6 million
of disallowed power costs at Connecticut Valley. Offsetting this increase is
the impact at Connecticut Valley totaling $11.0 million associated with the
reversal of a $5.5 million charge-off during 1998 and charge-off during 1997
of $5.5 million. See Electric Utility Restructuring-New Hampshire discussed
below and Note 13 to the Consolidated Financial Statements for additional
information.
The increase in purchased capacity cost of $13.1 million for 1997 over
1996 resulted from $7.4 million in higher prices, $.2 million increase in the
amount of MW purchased and $5.5 million representing Connecticut Valley's
estimated loss on power contracts for the twelve months following December 31,
1997 discussed below and in Note 13 to the Consolidated Financial Statements.
Pursuant to a PSB Accounting Order, during the first half of 1997, the
Company reduced capacity costs by $5.8 million related to the Hydro-Quebec
agreement for which a payment of $5.8 million was received from Hydro-Quebec
on June 30, 1997.
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 increase in
energy costs for 1998 resulted from a 11.1% or, $8.0 million increase in cost
per MWH purchased and a $.2 million increase in the amount of MWH purchased.
The price increase results primarily from the higher costs under the
Hydro-Quebec power contract, increased purchases from small power producers
and the
Vermont Yankee extended outage.
The increase in energy costs for 1997 resulted from a 5.0% or
$3.4 million increase in cost per MWH purchased and a .7%, or $.5 million
increase in the amount of MWH purchased. The price increase results primarily
from incremental replacement power costs associated with Unit #3 discussed
above. For information related to recovery of costs associated with the
premature retirement of the Maine Yankee and Connecticut Yankee nuclear power
plants see Note 2 to the Consolidated Financial Statements.
The Company is responsible for paying its entitlement percentage of
decommissioning costs for Vermont Yankee, Connecticut Yankee, Maine Yankee and
Yankee Atomic as well as its joint ownership percentage of decommissioning
costs for Unit #3. See Notes 2 and 14 to the Consolidated Financial
Statements. The staff of the Securities and Exchange Commission has
questioned certain current accounting practices of the electric utility
industry, including the Company, regarding the recognition, measurement and
classification of decommissioning costs for nuclear generating stations in
financial statements of electric utilities. In response to these questions,
the Financial Accounting Standards Board has agreed to review the industry-
wide accounting for nuclear decommissioning costs. If current electric
utility industry accounting practices for such decommissioning costs are
changed, it is possible that annual expense 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.
Millstone Unit #3 resumed operation in June 1998, accordingly, production
fuel costs increased for 1998 compared to 1997. Also, due to increased
generation at the Wyman #4 and the Joseph C. McNeil generating stations,
production fuel costs increased for 1997 compared to 1996.
In order to optimize its power mix for baseload, intermediate and peaking
power, the Company engages in purchases and sales with other electric
utilities, primarily in New England and with NEPOOL. The profits from these
transactions are used to reduce purchased power costs. The Company also
engages in marketing activities with Virginia Power which jointly supply
wholesale power in New England.
Based on present commitments and contracts, the Company expects that net
purchased power and production fuel costs will be approximately
$127.0 million, $143.0 million and $143.0 million for the period 1999 through
2001.
Production and transmission Due to increased production costs, primarily
related to Unit #3 and higher transmission costs, production and transmission
expenses increased $1.5 million in 1997 compared to 1996.
Other operation expenses Primarily due to increased legal and regulatory
expenses, other operation expenses increased $3.2 million for 1998 compared to
1997.
Other operation expenses, in 1997, increased $2.8 million compared to
1996 resulting primarily from increased amortization of conservation and load
management costs combined with a decrease in deferral of conservation and
load management costs.
Maintenance expenses Maintenance expenses associated with the Company's joint
ownership interest in Unit #3 decreased for 1998 compared to 1997. However,
this decrease was offset by an increase in maintenance expenses associated
with the Company's tree trimming program and expenses attributable to the
severe ice storm in January 1998. The increase in maintenance expenses for
1997 compared to 1996 is due to increased Unit #3 maintenance costs.
Income taxes Federal and state income taxes fluctuate with the level of
pre-tax earnings. These taxes decreased for 1998 and 1997 as a result of lower
pre-tax earnings.
Other Income, net Total other income, net decreased for 1998 compared to 1997
and increased in 1997 over 1996 as the result of gains of $5.0 million from
non-recurring asset sales. Also, Other income, net for 1996 and 1997 include
$2.3 million and $.4 million of expenses incurred in connection with the
Gauley River Power project, currently under construction, in Summersville,
West Virginia.
Other interest expense Other interest expense increased for 1998 due to an
increase in outstanding short-term debt offset somewhat by lower interest
rates. Other interest expense declined for 1997 due to a decrease in
short-term debt levels.
Extraordinary credit (charge) As a result of legal and regulatory actions
associated with Connecticut Valley, the Company, in 1997, recorded an
extraordinary charge of $.8 million. See Electric Utility Restructuring-
New Hampshire below.
Cash Dividends Declared
Common
Due to an early common dividend declaration made in December 1997 for the
quarterly dividend paid on February 13, 1998, common dividends declared
decreased for 1998 compared to 1997 and increased for 1997 compared to 1996.
Liquidity and Capital Resources
The Company's liquidity is primarily affected by the level of cash
generated from operations and the funding requirements of its ongoing
construction and C&LM programs. Net cash provided by operating activities
generated $21.7 million in 1998, $42.0 million in 1997 and $43.0 million in
1996.
The Company ended 1998 with cash and cash equivalents of $10.1 million, a
decrease of $6.5 million from the beginning of the year. The decrease in cash
for 1998 was the result of $21.7 million provided by operating activities,
$18.4 million used for investing activities and $9.8 million used for
financing activities.
Operating Activities Net income, depreciation and deferred income taxes and
investment tax credits provided $14.7 million. $7.0 million was provided from
fluctuations in working capital and other operating activities.
Investing Activities Construction and plant expenditures consumed
$16.0 million while $5.3 million was used for C&LM programs and non-utility
investments. $2.9 million was provided by a reduction in an escrow account to
fund a non-utility investment.
Financing Activities Dividends paid on common stock were $10.1 million, while
preferred stock dividends were $1.9 million. Retirement of long-term debt and
retirement of preferred stock required $20.5 million and $1.0 million,
respectively, and reduction in capital lease obligations required
$1.1 million. Short-term obligations and sale of common stock provided
$24.3 million and $.5 million, respectively.
Excluding allowance for funds used during construction, construction
expenditures are estimated at $18.0 million, $16.0 million and $16.0 million
for the years 1999 through 2001, respectively.
The level of short-term borrowings fluctuates based on seasonal corporate
needs, the timing of long-term financings and market conditions.
The Company has a $50.0 million revolving credit facility with a group of
banks maturing June 1, 1999 of which $25.0 million was outstanding at
December 31, 1998. The Company expects that borrowings will be $25.0 million
by June 1, 1999. The Company must rollover an aggregate of $16.3 million of
letters of credit between December 1999 and May 2000. In addition, the
Company has a $12.0 million accounts receivable facility which matures in
November 1999. The Company's ability to extend or replace the maturing $50.0
million revolving credit facility, roll over $16.3 million of maturing letters
of credit and extend the accounts receivable facility will be dependent in
large part on a positive outcome of the pending Hydro-Quebec Contract issues
at the VSC or progress made in power contract renegotiations. Negotiations
are ongoing with the banks to extend the maturities of these financial
arrangements.
Connecticut Valley has outstanding long-term bank debt of $3.75 million
maturing December 27, 1999. In regard to Connecticut Valley's long-term debt
see Note 7 to the Consolidated Financial Statements. Also see Electric
Industry Restructuring-New Hampshire for additional discussion of certain
events which may lead to an acceleration of the repayment date of this loan.
If the Company is unable to extend the maturities of or replace the bulk
of the debt and letters of credit facilities referenced above, it would
jeopardize the Company's ability to continue as a going concern. There can be
no assurance that the Company will be successful in extending or replacing
these credit facilities.
On June 3, 1996, the Company's Board of Directors increased the quarterly
dividend rate from $.20 to $.22 payable August 15, 1996.
The Company, through a common stock repurchase program initiated in 1994
and subsequently suspended in order to preserve capital for use in industry
restructuring and other business purposes, purchased 324,717 shares of its
common stock in open market transactions during 1995, 1996 and 1997 at an
average price of $13.19 per share. These transactions are recorded as
treasury stock, at cost, in the Company's Consolidated Balance Sheet.
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
1998 1997 1996
Common stock equity 56% 54% 53%
Preferred stock 8 8 8
Long-term debt 31 33 34
Capital lease obligations 5 5 5
___ ___ ___
100% 100% 100%
=== === ===
On February 2, 1999, Standard & Poor's Corporation (Standard & Poor's)
lowered its corporate credit rating on the Company to triple-'B'-minus from
triple-'B', the senior secured rating to triple-'B'-plus from
single-'A'-minus, and the preferred stock rating to double-'B'-plus from
triple-'B'-minus. In addition, the ratings were also placed on Credit
Watch with
negative implications.
Standard & Poor's stated "the CreditWatch listing reflects the
potentially adverse impact of pending legal and regulatory decisions that
could seriously weaken the Company's credit profile. The downgrades reflect
increased business risk and weakened financial measures as a result of recent
regulatory decisions in Vermont and New Hampshire and an adverse ruling by the
United States First Circuit Court of Appeals."
Standard & Poor's also said "Resolution of the CreditWatch listing will
depend on the outcome of the pending Federal Energy Regulatory Commission case
and other legal proceedings at State and Federal levels, which could be
resolved in 1999. Adequate rate relief and successful mitigation of high
power costs through contract renegotiations or other methods are essential to
stabilizing the ratings."
On February 17, 1999, Duff & Phelps Credit Rating Co. (Duff & Phelps)
placed the credit ratings of the Company on Rating Watch-Down due to the high
level of regulatory and public policy uncertainty in Vermont and the recent
unfavorable ruling by the United States Court of Appeals relating to
Connecticut Valley, the Company's wholly owned New Hampshire subsidiary.
Duff & Phelps stated "recent negative rulings by the PSB regarding
purchased power costs and the high level of uncertainty with public policy
toward electric utilities in Vermont adds risk to the Company's financial
profile going forward."
Current credit ratings by Duff & Phelps remain at 'BBB' (Triple-B) for
first mortgage bonds and 'BBB-' (Triple-B-Minus) for preferred stock.
The Company's declining credit ratings as well as continuing uncertainty
raise significant doubt regarding the Company's ability to extend or replace
maturing debt and letters of credit arrangements.
Current credit ratings of the Company's securities by Duff & Phelps and
Standard & Poor's are as follows:
Duff & Standard
Phelps & Poor's
Corporate Credit Rating BBB-
First Mortgage Bonds BBB BBB+
Preferred Stock BBB- BB+
On November 12, 1998, Catamount, a wholly owned non-utility subsidiary of
the Company, replaced its $8.0 million credit facility with a $25.0 million
revolving credit facility expiring November 11, 2002 which provides for up to
$25.0 million in revolving credit loans and letters of credit. Catamount
currently has a $1.2 million letter of credit outstanding to support certain
of its obligations in connection with a debt service requirement in the
Appomattox Cogeneration project and aggregated letters of credit of $11.0
million in support of construction and equity commitments for its Gauley River
Power project.
SmartEnergy, also a wholly owned non-utility subsidiary of the Company,
maintained a $.5 million revolving line of credit with a bank to provide
working capital and financing assistance for investment purposes. SmartEnergy
had outstanding borrowings under this facility of $25,000 at December 31,
1997. This line of credit was cancelled on February 9, 1998.
Financial obligations of the non-utility wholly owned subsidiaries are
non-recourse to the Company.
Hydro-Quebec Contract
The Company is a party to a power contract with Hydro-Quebec through the
Vermont Joint Owners (VJO), a consortium of Vermont utilities which includes
the Company, Green Mountain Power Corporation (GMP), Citizen's Utilities,
Rochester Electric Light & Power and Vermont Public Power Supply Authority
representing municipalities and a cooperative in Vermont. Under these
agreements, there are step up provisions that provide that in the event any
VJO member fails to meet its obligation under the contract with Hydro-Quebec,
the balance of the VJO participants, including the Company, will "step up" to
the defaulting party's share on a pro-rata basis. As of December 31, 1998 the
Company's VJO obligation is approximately 46% or $1.0 billion on a nominal
basis over the term of the contract ending in 2016. The total VJO contract
obligation on a nominal basis over the term of the contact is approximately
$2.3 billion.
During January 1998, a significant ice storm affected parts of New York,
New England and the Province of Quebec, Canada. This storm damaged major
components of the Hydro-Quebec transmission system over which power is
supplied to Vermont under the VJO contract with Hydro-Quebec. This resulted
in an interruption of a significant portion of scheduled contractual power
deliveries into Vermont. The ice storm's effect on Hydro-Quebec's
transmission system caused the VJO to examine Hydro Quebec's overall
reliability and ability to deliver energy in the future. That review has
prompted the VJO to initiate an arbitration proceeding, the end result of
which may be the termination of the Contract. By way of the arbitration, the
VJO is also seeking to recover capacity payments made during the period of
non-delivery.
Diversification Catamount was formed for the purpose of investing in non-
regulated power plant projects. Currently, Catamount, through its wholly
owned subsidiaries, has interests in five operating independent power projects
located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate,
Vermont; and Hopewell, Virginia. In addition, Catamount has interests in
projects under construction in Thetford, England, and in Summersville,
West Virginia, and under development in Fort Dunlop, England. Catamount's
after-tax earnings were $3.3 million, $4.1 million and $.5 million for 1998,
1997 and 1996, respectively. Earnings for 1997 include a net of tax gain
of $1.8 million from the sale of NW Energy Williams Lake L.P. Also, results
of operation for 1997 and 1996 include $.4 million and $2.3 million of pre-tax
expenses related to the Gauley River project currently under construction in
Summersville, West Virginia.
SmartEnergy was formed to engage in the sale of or rental of electric
water heaters, energy efficient products and other related goods and services.
SmartEnergy incurred losses of $1.5 million and $.7 million for 1998 and 1997,
respectively, and earnings of $.3 million for 1996.
Rates and Regulation The Company recognizes that adequate and timely rate
relief is necessary if the Company is to maintain its financial strength,
particularly since Vermont regulatory rules do not allow for changes in
purchased power and fuel costs to be passed on to consumers through automatic
rate adjustment clauses. The Company's practice of reviewing costs
periodically will continue and rate increases will be requested when
warranted.
1998 Retail Rate Case: On June 12, 1998, the Company filed with the PSB for a
10.7% retail rate increase to be effective March 1, 1999. This rate case
proceeding overlapped the 6.6% rate increase request referenced below that is
now stayed pending a review on the so-called preclusion issue by the VSC. On
October 27, 1998, the Company reached an agreement with the DPS regarding the
10.7% rate increase request.
The agreement, which was approved by the PSB on December 11, 1998,
provides for a temporary rate increase in the Company's Vermont retail rates
of 4.7% or $10.9 million on an annualized basis beginning with service
rendered January 1, 1999 and sets the Company's authorized return on equity in
its Vermont retail business at 11% before disallowances in connection with the
Hydro-Quebec Contract. The rate increase is temporary insofar as it is
subject to adjustment upon future resolution of the Hydro-Quebec Contract
issues presently before the VSC. The Company anticipates a resolution of the
Hydro-Quebec issues before the VSC by the end of 1999.
The agreement incorporates a disallowance of approximately $7.4 million
for the Company's purchased power costs under the Hydro-Quebec Contract while
the VSC reviews the PSB denial of the Company's claim that the PSB is
precluded from again trying the Company on certain Hydro-Quebec Contract
issues. Upon approval of the agreement by the PSB, the Company, during the
fourth quarter of 1998, recorded a loss of $7.4 million on a pre-tax basis for
disallowed purchased power costs, representing the Company's estimated under
recovery of power costs under the Hydro-Quebec Contract. This $7.4 million
disallowance was calculated using the same formula as contained in the rate
order issued by the PSB in the Green Mountain Power Corporation (GMP) rate
case on February 28, 1998 (see additional information below).
If the Company receives an unfavorable ruling from the VSC, and the PSB
issues a rate order adopting the methodology used to determine the temporary
Hydro-Quebec disallowance for the duration of the Hydro-Quebec Contract,
approximately $205.0 million of power costs to be incurred under that contract
would not be recoverable in rates. This would result in an immediate charge
to earnings of $205.0 million once such outcome became probable. Such an
outcome would jeopardize the ability of the Company to continue as a going
concern.
1997 Retail Rate Case: On September 22, 1997, the Company filed for a 6.6% or
$15.4 million general rate increase to become effective June 6, 1998 to offset
the increasing cost of providing service. $14.3 million or 92.9% of the rate
increase request was to recover contractual increases in the cost of power the
Company purchases from Hydro-Quebec. At the same time, the Company also filed
a request to eliminate the winter-summer rate differential and price
electricity the same year-round. The change would be revenue-neutral within
classes of customers and overall. Over time, customers would see a leveling
off of rates so they would pay the same per kilowatt-hour during the winter
and summer months.
The PSB decided to appoint an independent investigator to examine the
Company's decision to buy power from Hydro-Quebec. The Company filed a motion
with the PSB stating that the PSB already examined the Company's decision to
buy power from Hydro-Quebec and, therefore, the PSB as well as other parties
should be barred from reviewing its past decision on Hydro-Quebec. However,
the Company does not object to the independent investigator or others looking
at issues of management of the power supply since the Company's last rate
case.
During February 1998, the DPS filed testimony in opposition to the
Company's 6.6% or $15.4 million retail rate increase request. As a result of
its testimony, the DPS recommended that the PSB instead reduce the Company's
current retail rates by 2.5% or $5.7 million.
On February 28, 1998 the PSB issued an Order in a GMP rate case. That
Order found GMP's decision to lock-in the Hydro-Quebec VJO contract in 1991
imprudent and further found that the contract was not used and useful. As
such, the PSB concluded that a large portion of the contract's current costs
should not be imposed on consumers and were disallowed. GMP appealed this
rate order to the VSC. The Company is one of the participants in the VJO
contract. If the Company were to receive an order similar to that obtained by
GMP, such an order could have a material adverse effect on the Company's
results of operation and financial condition. If the Company were to
eventually receive a rate order that would result in disallowance of
Hydro-Quebec power costs on a permanent basis similar to that contained in
the GMP
February 28, 1998 rate order, the Company's ability to continue as a going
concern would be jeopardized. Because of these risks and because the PSB
rejected the Company's claim that the PSB was precluded from again trying the
Company on certain Hydro-Quebec and related demand side management issues.
1996 Retail Rate Case: The Company filed for a 14.6% or $31.0 million general
rate increase on October 17, 1995 to become effective July 1, 1996. On
February 13, 1996, the Company reached an agreement with the DPS regarding
this rate increase request. On April 30, 1996, the Company received a rate
order from the PSB generally approving the agreement.
Connecticut Valley: On November 24, 1998, Connecticut Valley filed with the
NHPUC its annual FAC/PPCA rates to be effective January 1, 1999. On January
4, 1999, the NHPUC issued an Order allowing Connecticut Valley to increase the
proposed FAC rate of $.008 per kWh and the proposed PPCA rate of $.01000 per
kWh rate on a temporary basis, effective on all bills rendered on or after
January 1, 1999. In addition, the NHPUC ordered Connecticut Valley to pay
refunds plus interest to its retail customers for any overcharges collected as
a result of the April 9, 1998 Federal District Court Order, should it be
overturned or modified. See Electric Industry Restructuring-New Hampshire for
additional information related to the Court Order.
On November 26, 1997, Connecticut Valley filed a request with the NHPUC
to increase the FAC/PPCA and short-term energy purchase rates effective on or
after January 1, 1998. The requested increase in rates resulted from higher
forecast energy and capacity charges on power Connecticut Valley purchases
from the Company plus removal of credit effective during 1997 to refund
overcollections from 1996.
In an Order dated December 31, 1997 in Connecticut Valley's FAC and PPCA
docket, the NHPUC found Connecticut Valley acted imprudently by not
terminating the wholesale contract between Connecticut Valley and the Company,
notwithstanding the stays of its February 28, 1997 Orders. The NHPUC Order
further directed Connecticut Valley to freeze its current FAC and PPCA rates
(other than short term rates to be paid to certain Qualifying Facilities)
effective January 1, 1998, on a temporary basis, pending a hearing to
determine: 1) the appropriate proxy for a market price that Connecticut Valley
could have obtained if it had terminated its wholesale contract with the
Company; 2) the implications of allowing Connecticut Valley to pass on to its
customers only that market price; and 3) whether the NHPUC's final
determination on the FAC and PPCA rates should be reconciled back to
January 1, 1998 or some other date. See Electric Industry Restructuring
discussed below and Note 13 to the Consolidated Financial Statements for
additional information.
On July 23, 1996, Connecticut Valley filed with the NHPUC for an 8.8% or
$1.6 million base rate increase to become effective September 22, 1996. The
increase was to recover increased operating costs and costs of improvements to
the electric system. As part of the permanent rate increase, Connecticut
Valley also requested a temporary rate increase of 5.4% or $.9 million. The
NHPUC granted Connecticut Valley a temporary rate increase of 5.4% effective
with bills rendered October 1, 1996. On January 21, 1997, Connecticut Valley
and the NHPUC Staff reached a settlement in principle regarding the permanent
rate increase. The settlement, approved by the NHPUC, provided for a 6.4%
permanent rate increase and sets Connecticut Valley's allowed return on common
equity at 10.2%. Recoupment revenues for the period October 1, 1996 and
March 30, 1997, and rate case expenses were recovered through a temporary
billing surcharge of approximately 2.2% of total bill effective during the
period April 1 through November 30, 1997, when off-peak rates were in effect.
As approved by the NHPUC, this billing surcharge resumed on March 1, 1998 to
recover expenses incurred in connection with the pilot program.
Management Audit
On April 17, 1997, the PSB ordered an independent forward-looking
analysis of three of the Company's management policies and practices focusing
on three areas: 1) Transmission of information to the Company's Board of
Directors by management; 2) cost-benefit analyses for major corporate
decisions; and 3) implementation of the Company's ethics and conflict of
interest policy. The PSB's consultant began work on the project during the
first quarter of 1998 and issued a final report during October 1998. Although
the final report suggested areas where the Company could improve, it was
generally very positive of the Company and as a result the PSB has terminated
the proceeding.
Proposed Formation of Holding Company
In order to further prepare Central Vermont Public Service Corporation
for deregulation, on July 24, 1998, the Company filed a petition with the PSB
for permission to create a holding company that would have as subsidiaries the
Company and non-utility subsidiaries, Catamount and SmartEnergy. The Company
believes that a holding company structure will facilitate the Company's
transition to a deregulated electricity market. The proposed holding company
formation must also be approved by Federal regulators, including the
Securities and Exchange Commission and the FERC, and by the Company's
shareholders.
Year 2000 Information Systems Modifications The Company's information systems
could be affected by the date change in Year 2000 because most software
application and operational programs will not properly recognize calendar
dates beginning in the Year 2000. If not corrected, many computer
applications could fail or create erroneous results. In order to meet current
and future business needs the Company retained outside consultants to make its
customer service applications Year 2000 compliant. In addition, the Company
utilized both internal and external resources to make other applications,
including its desk top applications, Year 2000 ready. Inventory and
assessment activities are 100% complete. Overall remediation efforts are
estimated to be at approximately 90% complete by the end of the first quarter
of 1999. The Company expects to achieve compliance with Year 2000
requirements for all of its financial and operating systems by the end of the
second quarter of 1999.
The Company's operations would be adversely affected if a date-related
system failure occurred with one of its major power suppliers, such as
Hydro-Quebec or Vermont Yankee, or Velco, the company responsible for
transmission
in Vermont. Velco indicates it will be compliant by September 1999. Other
delivery systems outside the state could, in the event of a date-related
system failure, cause additional power supply interruptions. The Company has
requested written reports from its power supply vendors regarding each
Company's status relative to Year 2000 compliance and based on responses to
date, these power supply vendors have indicated that they are either currently
compliant or expect to be compliant by June 1999.
The Company has also requested compliance information from other major
vendors and suppliers. While this process is not yet complete, based upon
responses to date, many of those major vendors and suppliers have indicated
that they will be Year 2000 compliant in a timely manner. However, there can
be no guarantee that third parties' noncompliance and their failure to
remediate Year 2000 issues would not have a material adverse effect on the
Company.
Failure on the part of the Company to comply by December 31, 1999 could
have a material adverse effect on the Company's results of operations and
financial condition. Also, failures of the Company's principal power and
transmission suppliers to remedy Year 2000 compliance issues, could have a
material adverse effect on the Company should non-compliance result
interruptions of power supply and transmission.
The Company is part of the Northeast grid contingency plan that would go
into effect immediately which would provide electricity to its customers on a
priority basis in the event of power outages. The Company also has
contingency plans developed in the event of the failure of its transmission,
generation, distribution, metering, telecommunications, information and
public communications systems.
The Company believes it will incur approximately $3.3 million of costs
associated with making the necessary modifications to its centralized and
non-centralized computer systems. As of December 31, 1998, approximately
$2.7 million of those costs have been incurred.
During the first quarter of 1998, the Company requested an Accounting
Order from the PSB to defer these operating and maintenance costs. On
August 31, 1998, the PSB issued an Accounting Order authorizing the Company to
defer these costs and amortize them over a five-year period beginning
January 1, 2000.
Per PSB Order dated December 11, 1998, the Company is authorized to
recover these costs through the regulatory process.
ELECTRIC INDUSTRY RESTRUCTURING
The electric utility industry is in a period of transition that may
result in a shift away from ratemaking based on cost of service and return on
equity to more market-based rates. Many states, including Vermont and
New Hampshire, where the Company does business, are exploring new mechanisms
to bring greater competition, customer choice and market influence to the
industry while retaining the public benefits associated with the current
regulatory system.
Vermont
On December 31, 1996, the PSB issued a Report and Order (the Report)
outlining a restructuring plan (the Plan), subject to legislative approval,
for the Vermont electric utility industry.
Due to uncertainty surrounding legislative schedules, the PSB, on
April 18, 1997, issued an Order which suspended, pending further legislative
action or future PSB Orders, certain filing deadlines for reports and plans to
be completed in connection with the Plan.
On April 3, 1997, Senate Bill 62 (S.62), an act relating to electric
industry restructuring was passed by the Vermont Senate. Pursuant to S.62,
electric utility customers would have been entitled to purchase electricity in
a competitive market place and could have chosen their electricity supplier.
Incumbent investor-owned electric utilities, including the Company, would have
been required to separate their regulated distribution and transmission
operations from the competitive generation and retail operations. S.62
provided for the recovery of a portion of investor-owned utility's "above
market costs" which became stranded on account of the introduction of
competition within their service area. When considering the recovery of such
amounts, S.62 would have required the PSB to weigh the goal of sharing net
prudently incurred, discretionary above-market costs "evenly" between
utilities and customers against other goals including preserving the
continuing financial integrity of the existing utility and respecting the just
interests of investors. The Company believes that the unmodified provisions
of S.62 would not have met the criteria for continuing application of SFAS
No. 71. S.62 also created an incentive for the Company to take steps to close
the Vermont Yankee Nuclear Power Station by conditioning the recovery of
certain plant-related stranded costs on the decision of its owners to cease
operations in 1998, unless the PSB agreed to allow the plant to run for up to
two more refuelings to avoid power shortages or for other public interest
reasons. To become law, S.62 would have had to be passed by the Vermont House
of Representatives and signed by the Governor of the State of Vermont. Since
the 1998 Legislative session concluded in April 1998 and S.62 was not enacted
by the Vermont House of Representatives and subsequently signed into law by
the Governor of Vermont, the bill did not become law and any efforts to pursue
it in the future will require that it be re-enacted by the Vermont Senate and
passed by the Vermont House of Representatives.
Instead of considering S.62, the Vermont House of Representatives
convened a special committee to study matters relating to the reform of
Vermont's electric utility system in the summer of 1997. That committee
issued recommendations in a report and legislation was proposed that would
have provided for reform but not adopt the recommendations concerning customer
choice and competition set forth in the PSB's Report and Order. Other
legislation intended to advance a portion of the PSB Report and Order was also
introduced. However, neither the House of Representatives nor Vermont Senate
acted on these reforms which must be reintroduced in the next Vermont
legislative biennium that began in January 1999, if they are to be considered.
Therefore, at this time, it cannot be determined whether future restructuring
legislation will be enacted in 1999 that would conform to the concepts
developed by the Report, S.62 or the House Special Committee report.
On July 22, 1998, Governor Dean issued an Executive Order establishing a
Working Group on Vermont's Electricity Future (the Working Group) to lead a
new effort to review the issues of potential restructuring of Vermont's
electric industry. The Working Group was created to determine how
restructuring the electric industry in Vermont can reduce both current and
long-term electric costs for all classes of Vermont electric consumers. The
Working Group was asked to provide a fact-based analysis of the options for
electric industry restructuring and the impact of such industry changes on
consumers and upon Vermont utilities. Further, the Working Group was directed
by Governor Dean to gather information on and evaluate the possible
consequences of the current financial status of Vermont electric utilities.
The Working Group was asked to complete its review and report back to Governor
Dean and to legislative leaders by December 15, 1998.
A report was issued by the Working Group on December 18, 1998. Key
conclusions of its report are:
1. Vermont should restructure its electric industry by moving rapidly to
retail choice whereby consumers would purchase power directly from competing
power suppliers.
2. Bankruptcy of Vermont electric utilities should not be viewed as an
appropriate means to reduce Vermont utilities' above market power supply
costs.
3. Vermont electric utilities should pursue power contract renegotiations
through payments to buy down power contracts or buy-out power contracts.
Financing for such payments should be obtained in the capital markets after a
comprehensive regulatory process dealing with all of the elements of the
restructuring of the Vermont electric utility industry.
4. The Vermont electric utilities should pursue auctions of their power
generation assets and remaining power contracts.
5. Consolidation of existing electric utilities in Vermont (there are
currently 22 utilities) should be considered in order to effect additional
savings for utility customers.
The Working Group noted that by March 1, 2000, most New Englanders
outside Vermont will have a choice of their power supplier. While New England
has the highest rates in the nation, electricity costs in Vermont have been
among the lowest in the region. However, that advantage is eroding as other
states in New England restructure their electric utility industries.
Therefore, the Working Group recommends that it is in the interest of Vermont
ratepayers to have the benefit of a restructured electric utility industry as
soon as possible.
The Company has signed a confidentiality and cooperation agreement with
GMP and Citizens Utilities to permit an exchange of information to evaluate
the possibility of consolidating the Vermont operations of the three
utilities. In addition, the Washington Electric Cooperative (WEC) has
recommended that consideration be given to its acquiring Vermont's investor
owned utilities and converting them to a cooperative ownership structure.
The Company supports the Working Group recommendations and will work with
the PSB and other parties to implement the plan. However, there can be no
assurance that the plan or its key elements, including consolidation, will
ultimately be implemented.
On August 27, 1998, the PSB hosted a workshop entitled, "Electricity
Futures: Reforming Vermont's Power Supply", which was organized to facilitate
power supply reform. Participants heard reports on successful power supply
reforms in other states, followed by a discussion intended to identify
opportunities and next steps, and to elicit proposals for reformulating
Vermont's electric power supply. This workshop generated a great deal of
interest with over 140 attendees, representing Vermont retail electric
utilities, both large and small electricity consumers, public officials and
interest groups, and several current and aspiring energy suppliers. As a
follow up to the workshop, on September 15, 1998, the PSB opened a formal
proceeding in Docket No. 6140 with the goal of creating a regulatory
environment and a procedural framework to call forth, for disciplined review,
proposals for reducing current and future power costs in Vermont. The PSB
explained that it intends that this proceeding will define one or more
acceptable courses for reform, and will create the framework to enable Vermont
utilities and other interested parties to pursue them and to present them for
regulatory approval in an open, public process. All Vermont utilities were
made a party to that proceeding. Subsequent to the PSB's announcement,
preliminary position papers were filed and a series of technical conferences
were convened with the PSB to recommend the scope of the investigation,
potential courses for reform of Vermont's power supply and other matters
associated therewith including the consideration of the Working Group's
recommendations as well as the WEC acquisition proposal. As of this time, the
PSB has yet to act on any of the proposal or recommendations made concerning
the disposition of the matters in Docket No. 6140.
As a companion proceeding to its investigation in Docket No. 6140, on
January 19, 1999, the PSB issued an Order opening a new contested case
proceeding, Docket No. 6140-A, where it intends to issue final, binding and
appealable orders concerning matters related to the reform and restructuring
of Vermont's electric utility industry. Initially, the PSB noticed parties
that it intended proceedings in Docket No. 6140-A to consider matters
associated with the bankruptcy of one or more of the Vermont electric
utilities. After an opportunity for comment, the focus of the proceeding was
amended to first consider the principles, authority and proposals for reform
of Vermont's electric power supply. This will include issues associated with
the scope and extent of the Board's authority to approve "securitization" and
other financings proposed to be entered into in connection with the buy-out or
buy-down of power contracts and the criteria to be applied by the PSB when
considering voluntary utility restructuring proposals. The PSB explains that
this proceeding will provide utilities the maximum structural guidance on the
terms and conditions it will consider in a voluntary restructuring proposal.
As of this time, formal proceedings in Docket No. 6140-A are only at a
preliminary status however the PSB indicates that it will proceed quickly to
conclude this proceeding.
New Hampshire
On February 28, 1997 the NHPUC published its detailed Final Plan to
restructure the electric utility industry in New Hampshire. Also on
February 28, 1997, the NHPUC, in a supplemental order specific to Connecticut
Valley, found that Connecticut Valley was imprudent for not terminating the
FERC-authorized power contract between Connecticut Valley and the Company,
required Connecticut Valley to give notice to cancel its contract with the
Company and denied stranded cost recovery related to this power contract.
Connecticut Valley filed for rehearing of the February 28, 1997 NHPUC Order.
On April 7, 1997, the NHPUC issued an Order addressing certain threshold
procedural matters raised in motions for rehearing and/or clarification filed
by various parties, including Connecticut Valley, relative to the Final Plan
and interim stranded cost orders. The April 7, 1997 Order stayed those
aspects of the Final Plan that were the subject of rehearing or clarification
requests and also stayed the interim stranded cost orders for the various
parties, including Connecticut Valley. As such, those matters pertaining to
the power contract between Connecticut Valley and the Company were stayed.
The suspension of these orders was to remain in effect until two weeks
following the issuance of any order concerning outstanding requests for
rehearing and clarification.
On March 20, 1998, the NHPUC issued an order which affirmed, clarified
and modified various generic policy statements including the reaffirmation to
establish rates on the basis of a regional average announced previously in its
February 28, 1997 Final Plan. The March 20, 1998 order also addressed all
outstanding motions for rehearings or clarification relative to the policies
or legal positions articulated in the Final Plan and removed the stay covering
the Company's interim stranded cost order of April 7, 1997. In addition, the
March 20, 1998 Order imposed various compliance filing requirements.
On November 17, 1997, the City of Claremont, New Hampshire (Claremont),
filed with the NHPUC a petition for a reduction in Connecticut Valley's
electric rates. Claremont based its request on the NHPUC's earlier finding
that Connecticut Valley's failure to terminate its wholesale power contract
with the Company as ordered in the NHPUC Stranded Cost Order of February 28,
1997 was imprudent. Claremont alleged that if Connecticut Valley had given
written notice of termination to the Company in 1996 when legislation to
restructure the electric industry was enacted in New Hampshire, Connecticut
Valley's obligation to purchase power from the Company would have terminated
as of January 1, 1998.
On November 26, 1997, Connecticut Valley filed a request with the NHPUC
to increase the FAC, PPCA and short-term energy purchase rates effective on or
after January 1, 1998. The requested increase in rates resulted from higher
forecast energy and capacity charges on power Connecticut Valley purchases
from the Company plus removal of a credit effective during 1997 to refund
overcollections from 1996. Connecticut Valley objected to the NHPUC's notice
of intent to consolidate Claremont's petition into the FAC and PPCA docket,
stating that Claremont's complaint should be heard as part of the NHPUC
restructuring docket. Over Connecticut Valley's objection at the hearing on
December 17, 1997, the NHPUC consolidated Claremont's petition with
Connecticut Valley's FAC and PPCA proceeding.
In an Order dated December 31, 1997 in Connecticut Valley's FAC and PPCA
docket, the NHPUC found Connecticut Valley acted imprudently by not
terminating the wholesale contract between Connecticut Valley and the Company,
notwithstanding the stays of its February 28, 1997 Orders. The NHPUC Order
further directed Connecticut Valley to freeze its current FAC and PPCA rates
(other than short term rates to be paid to certain Qualifying Facilities)
effective January 1, 1998, on a temporary basis, pending a hearing to
determine: 1) the appropriate proxy for a market price that Connecticut Valley
could have obtained if it had terminated its wholesale contract with the
Company; 2) the implications of allowing Connecticut Valley to pass on to its
customers only that market price; and 3) whether the NHPUC's final
determination on the FAC and PPCA rates should be reconciled back to
January 1, 1998 or some other date.
On January 19, 1998, Connecticut Valley and the Company filed with the
District Court of Rhode Island (the Court) for a temporary restraining order
to maintain the status quo ante by staying the December 31, 1997 NHPUC Order
and preventing the NHPUC from taking any action that (i) compromises cost-
based rate making for Connecticut Valley or otherwise seeks to impose market
price-based rate making on Connecticut Valley; (ii) interferes with the FERC's
exclusive jurisdiction over the Company's pending application to recover
wholesale stranded costs upon termination of its wholesale power contract with
Connecticut Valley; or (iii) prevents Connecticut Valley from recovering
through retail rates the stranded costs and purchased power costs that it
incurs pursuant to its FERC-authorized wholesale rate schedule with the
Company.
On February 23, 1998, the NHPUC announced in a public meeting that it
reaffirmed its finding of imprudence and designated a proxy market price for
power at 4 cents per kWh in lieu of the actual costs incurred pursuant to the
wholesale power contract with the Company. In addition, the NHPUC indicated,
subject to certain conditions which were unacceptable to the companies, that
it would permit Connecticut Valley to maintain its current rates pending a
decision in Connecticut Valley's appeal of the NHPUC Order to the New
Hampshire Supreme Court.
Based on the December 31, 1997 NHPUC Order as well as the NHPUC's
February 23, 1998 announcement, which resulted in the establishment of
Connecticut Valley's rates on a non cost-of-service basis, Connecticut Valley
no longer qualified, as of December 31, 1997, for the application of SFAS
No. 71. As a result, Connecticut Valley wrote-off all of its regulatory
assets associated with its New Hampshire retail business as of December 31,
1997. This write-off amounted to $1.2 million on a pre-tax basis. In
addition, Connecticut Valley recorded a $5.5 million pre-tax loss in 1997 for
disallowed power costs.
On April 3, 1998, the Court held a hearing on the Companies' motion for a
Temporary Restraining Order (TRO) and Preliminary Injunction against the NHPUC
at which time both the Companies and the NHPUC presented arguments. In an
oral ruling from the bench, and in a written order issued on April 9, 1998,
the Court concluded that the Companies had established each of the
prerequisites for preliminary injunctive relief and directed and required the
NHPUC to allow Connecticut Valley to recover through retail rates all costs
for wholesale power requirements service that Connecticut Valley purchases
from the Company pursuant to its FERC-authorized wholesale rate schedule
effective January 1, 1998 until further court order. In compliance with that
order, Connecticut Valley received an order from the NHPUC authorizing retail
rates to recover such costs beginning in May 1998. On April 14, 1998, the
NHPUC filed a notice of appeal and a motion for a stay of the Court's
preliminary injunction. The NHPUC's request for a stay was denied. At the
same time, the NHPUC permitted Connecticut Valley to recover in rates the full
cost of its wholesale power purchases from the Company.
Also, on April 3, 1998, the Court indicated that its earlier TRO
enjoining the NHPUC's restructuring orders applied to Connecticut Valley and
prohibits the enforcement of the restructuring orders until the Court conducts
a consolidated hearing and rules on the requests for permanent injunctive
relief by plaintiff PSNH and the other utilities that have been allowed to
intervene in these proceedings, including the Company and Connecticut Valley.
The plaintiffs-intervenors filed a motion asking the Court to extend its stay
of action by the NHPUC to implement restructuring and to make clear that the
stay encompasses the NHPUC's order of March 20, 1998.
As a result of these Court orders, Connecticut Valley's 1997 charges
described above were reversed in the first quarter of 1998. Combined, the
reversal of these charges increased first quarter 1998 net income and earnings
per share of common stock by $4.5 million and $.39, respectively.
On April 1, 1998, Citizens Bank of New Hampshire (Bank) notified
Connecticut Valley that it was in default of the Loan Agreement between the
Bank and Connecticut Valley dated December 27, 1994 and that the Bank would
exercise all of its remedies from and after May 5, 1998 in the event that the
violations were not cured. After reversing the 1997 write-offs described
above, Connecticut Valley was in compliance with the financial covenants
associated with its $3.75 million loan with the Bank. As a result,
Connecticut Valley has satisfied the Bank's requirements for curing the
violation.
On May 11, 1998 the NHPUC issued an order requiring Connecticut Valley to
show cause why it should not be held in contempt for its failure to meet the
compliance filing requirements of its March 20, 1998 Order. A hearing on this
matter was scheduled for June 11, 1998, which was subsequently cancelled
because of the Court's June 5, 1998 Order, discussed below.
On June 5, 1998, the Court issued an Order which denied NHPUC's motion
for a stay of the Court's preliminary injunction. The Order clearly states
that no restructuring effort in New Hampshire can move forward without the
Court's approval unless all New Hampshire utilities agree to the plan. The
Order suspended all involuntary restructuring efforts for all New Hampshire
utilities until a hearing is conducted. The NHPUC appealed this Order to the
United States First Circuit Court of Appeals (Court of Appeals).
On December 3, 1998, the Court of Appeals announced its decisions on the
appeals taken by the NHPUC from the preliminary injunctions issued by the
Court. Those preliminary injunctions had stayed implementation of the NHPUC's
plan to restructure the New Hampshire electric industry and required the NHPUC
to allow Connecticut Valley to recover through its retail rates the full cost
of wholesale power obtained from the Company.
The Court of Appeals affirmed the preliminary injunction, issued by the
Court, staying restructuring until the plaintiff utilities' claims (including
those of the Company and Connecticut Valley) are fully tried. The Court of
Appeals found that PSNH had sufficiently established that without the
preliminary injunction against restructuring it would suffer substantial
irreparable injury and that it had sufficient claims against restructuring to
warrant a full trial. The Court of Appeals also affirmed the extension of the
preliminary injunction to protect the other plaintiff utilities, including
Connecticut Valley and the Company, although it questioned whether the other
utilities had as strong of arguments against restructuring as PSNH because
they did not have formal agreements with the State similar to PSNH's Rate
Agreement. The NHPUC filed a petition for rehearing on December 17, 1998.
The Court of Appeals denied the petition on January 13, 1999.
The Court of Appeals reversed the Court's preliminary injunction
requiring the NHPUC to allow Connecticut Valley to recover in retail rates the
full cost of the power it buys from the Company. Although the Court of
Appeals found that Connecticut Valley and the Company had made a strong
showing of irreparable injury to justify the preliminary injunction, it
concluded that Connecticut Valley's and the Company's claims did not have a
sufficient probability of success to warrant such preliminary relief. The
Court of Appeals explained that the filed-rate doctrine preserving the
exclusive jurisdiction of the FERC over wholesale power rates did not prevent
the NHPUC from deciding whether Connecticut Valley's power purchases from the
Company were prudent given alternative available sources of wholesale power.
The Court of Appeals then stated that Connecticut Valley's rates could be
reduced to the level prevailing on December 31, 1997. However, the Court of
Appeals also stated that if a reduction of existing rates were ordered "it
will be time enough to consider whether they are precluded from the Court's
injunction against the Final Plan or on other grounds."
On December 17, 1998, Connecticut Valley and the Company filed a petition
for rehearing on the grounds that the Court of Appeals had not given
sufficient weight to the Court's factual findings and that the Court of
Appeals had misapprehended both factual and legal issues. Connecticut Valley
and the Company also asked that the entire Court of Appeals, rather than only
the three-judge appellate panel that had issued the December 3 decision,
consider their petition for rehearing. On January 13, 1999, the Court denied
the petition for rehearing.
Connecticut Valley and the Company then requested the Court of Appeals to
stay the issuance of its mandate until the companies could file a petition for
certiorari to the United States Supreme Court and the Supreme Court acts on
the petition.
On January 22, 1999, the Court of Appeals denied the request. However,
the Court of Appeals granted a 21-day stay to enable the Company to seek a
stay pending certiorari from the Circuit Justice of the Supreme Court. On
February 11, 1999, the Company and Connecticut Valley filed a petition for a
writ of certiorari with the United States Supreme Court and a motion to stay
the effect of the Court of Appeals' decision while the case was pending in the
Supreme Court. The motion for a stay was addressed to Justice Souter who is
responsible for such motions pertaining to the Court of Appeals for the First
Circuit. On February 18, 1999, Justice Souter denied the stay pending the
petition for certiorari. No decision has been made by the Supreme Court
regarding the petition for certiorari.
On November 24, 1998, Connecticut Valley filed with the NHPUC its annual
FAC/PPCA rates to be effective January 1, 1999. On January 4, 1999, the NHPUC
issued an Order allowing Connecticut Valley to increase the proposed FAC rate
of $.008 per kWh and the proposed PPCA rate of $.01000 per kWh rate on a
temporary basis, effective on all bills rendered on or after January 1, 1999.
In that order the NHPUC reiterated its intent that, in the event the District
Court's April 9, 1998 preliminary injunction was vacated, the NHPUC would
lower CVEC's rates at least to the December 31, 1997 level and require a
refund for all funds collected in 1998 over that amount.
As a result of legal and regulatory actions discussed above, Connecticut
Valley no longer qualifies for the application of SFAS No. 71, and wrote-off
all its regulatory assets associated with its New Hampshire retail business
estimated at approximately $1.3 million on a pre-tax basis. In addition,
Connecticut Valley recorded estimated total losses of $4.3 million pre-tax for
disallowed power costs of $1.6 million and 1998 refund obligations of
$2.7 million. Company management, however, continues to believe that the
NHPUC's actions are illegal and unconstitutional and will present its
arguments in the appropriate forums.
The pre-tax losses described above resulted in Connecticut Valley
violating applicable covenants in its outstanding loan, which if not waived or
renegotiated, allows Connecticut Valley's lender the right to accelerate the
repayment of a $3.75 million loan with Connecticut Valley.
At a status conference on February 25, 1999, the Court indicated that it
would not establish a trial date on the Company and Connecticut Valley's
request for a permanent injunction until all pending motions, including a
motion to dissolve the stay of restructuring activities filed by the NHPUC,
and motions for summary judgement filed by the NHPUC, the Company and other
parties were heard and decided. Such an injunction, if granted, could require
the NHPUC to allow Connecticut Valley to recover the full cost of the
wholesale power obtained from the Company through its retail rates. However,
the Company cannot predict the outcome of this or any of the other related
litigation.
On June 25, 1997, the Company filed with the FERC a notice of termination
of its power supply contract with Connecticut Valley, conditional upon the
Company's request to impose a surcharge on the Company's transmission tariff
to recover the stranded costs that would result from the termination of its
contract with Connecticut Valley. The amount requested was $44.9 million plus
interest at the prime rate to be recovered over a ten-year period. In its
Order dated December 18, 1997 in Docket No. ER97-3435-000, the FERC rejected
the Company's proposed stranded cost surcharge mechanism but indicated that it
would consider an exit fee mechanism for collecting stranded costs. The FERC
also rejected the Company's arguments concerning the applicability of stated
FERC policies regarding retail stranded costs, multi-state regulatory gaps and
the implications of state restructuring initiatives. The Company filed a
motion seeking rehearing of the FERC's December 18, 1997 Order which was
denied. Thereafter, the Company appealed the FERC's decision to the Court of
Appeals for the District of Columbia circuit. In addition, and in accordance
with the December 18, 1997 FERC Order, on January 12, 1998 the Company filed a
request with the FERC for an exit fee mechanism to collect $44.9 million in a
lump sum, or in installments with interest at the prime rate over a ten-year
period, to cover the stranded costs resulting from the cancellation of
Connecticut Valley's power contract with the Company.
On March 11, 1998, the FERC issued an order accepting for filing the
Company's request for an exit fee effective March 14, 1998, and set hearings
to determine: whether Connecticut Valley will become an unbundled
transmission customer of the Company, the Company's expectation as to the
period of time it would serve Connecticut Valley, and the allowable amount of
the exit fee. The FERC also rejected the Company's June 25, 1997 notice of
termination indicating that the notice can be resubmitted when the power
contract is proposed to be terminated.
On April 28, 1998, the Company filed its case-in-chief before the FERC
updating the amount of the exit fee to $54.9 million which was subsequently
amended to $50.0 million in a lump sum, describing all of the ways Connecticut
Valley will become an unbundled transmission customer of the Company
subsequent to termination, and establishing the expected period of service
based upon the date of termination, whenever that occurs, and the weighted
average service life of its commitments to power resources to serve
Connecticut Valley. Had termination taken effect on January 1, 1998 this
expectation period would have equaled nineteen years.
On August 4 and 5, 1998 Phase 1 hearings were held at the FERC on the
issue of whether Connecticut Valley will become an unbundled transmission
customer of the Company. Subsequent to those hearings, the parties agreed to
go on to hearings on the Phase 2 issues (addressing the allowable amount of
the exit fee) without a preliminary determination from the Administrative Law
Judge or the FERC on the Phase 1 issues. The Company submitted supplemental
testimony on Phase 2 issues on December 3, 1998.
If the Company is unable to obtain an order authorizing the full recovery
amount of the exit fee, or other appropriate mechanism, the Company would be
required to recognize a loss under this contract totaling approximately
$60.0 million on a pre-tax basis. Furthermore, the Company would be required
to write-off approximately $4.0 million in regulatory assets associated with
its wholesale business on a pre-tax basis. Conversely, even if the Company
obtains a FERC order authorizing the updated requested exit fee, Connecticut
Valley would be required to recognize a loss of approximately $50.0 million on
a pre-tax basis unless Connecticut Valley has obtained an order by the NHPUC
or other appropriate body directing the recovery of those costs in Connecticut
Valley's retail rates. Either of these reasonably possible outcomes could
occur during calendar year 1999.
For further information on New Hampshire restructuring issues and other
regulatory events in New Hampshire affecting the Company or Connecticut Valley
and the 1997 and 1998 charges and reversals of the 1997 charges, see the
Company's Current Reports on Form 8-K dated January 12, 1998, January 28, 1998
and April 1, 1998 and February 1, 1999; the Company's Form 10-Q for the
quarterly periods ended March 31, June 30 and September 30, 1998; and Item 1.
Business-New Hampshire Retail Rates, Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations-Electric Industry
Restructuring-New Hampshire and Item 8. Financial Statements and Supplementary
Data-Note 13, Retail Rates-New Hampshire in the Company's 1997 Annual Report
on Form 10-K.
The Company has initiated and will continue to work for a negotiated
settlement with parties to the New Hampshire restructuring proceeding and the
NHPUC. On September 14 and 15, 1998 the Company participated in a settlement
conference with an administrative law judge assigned for the settlement
process at the FERC and the parties to the Company's exit fee filing. An
adverse resolution would have a material adverse effect on the Company's
results of operations, cash flows, and ability to obtain capital at
competitive rates. However, the Company cannot predict the ultimate outcome
of this matter.
Connecticut Valley constitutes approximately 7% of the Company's total
retail MWH sales.
Competition-Risk Factors
If retail competition is implemented in Vermont or New Hampshire, the
Company is unable to predict the impact of this competition on its revenues,
the Company's ability to retain existing customers and attract new customers
or the margins that will be realized on retail sales of electricity.
Historically, electric utility rates have been based on a utility's
costs. As a result, electric utilities are subject to certain accounting
standards that are not applicable to other business enterprises in general.
SFAS No. 71 requires regulated entities, in appropriate circumstances, to
establish regulatory assets and liabilities, and thereby defer the income
statement impact of certain costs and revenues that are expected to be
realized in future rates.
As described in Note 1 of Notes to Consolidated Financial Statements, the
Company believes it currently complies with the provisions of SFAS No. 71 for
both its regulated Vermont service territory and FERC regulated wholesale
businesses. In the event the Company determines that it no longer meets the
criteria for following SFAS No. 71, the accounting impact would be an
extraordinary, non-cash charge to operations of approximately $66.7 million on
a pre-tax basis as of December 31, 1998. Criteria that give rise to the
discontinuance of SFAS No. 71 include (1) increasing competition that
restricts the Company's ability to establish prices to recover specific costs
and (2) a significant change in the manner in which rates are set by
regulators from cost-based regulation to another form of regulation.
The Securities and Exchange Commission has questioned the ability of
certain utility companies continuing the application of SFAS No. 71 where
legislation provides for the transition to retail competition. Deregulation
of the price of electricity issues related to the application of SFAS No. 71
and 101, as to when and how to discontinue the application of SFAS No. 71 by
utilities during transition to competition has been referred to the Financial
Accounting Standards Board's Emerging Issues Task Force (EITF).
The EITF has reached a tentative consensus, and no further discussion is
planned, that regulatory assets should be assigned to separable portions of
the Company's business based on the source of the cash flows that will recover
those regulatory assets. Therefore, if the source of the cash flows is from a
separable portion of the Company's business that meets the criteria to apply
SFAS No. 71, those regulatory assets should not be written off under SFAS
No. 101, "Accounting for the Discontinuation of Application of SFAS No. 71,"
but should be assessed under paragraph 9 of SFAS No. 71 for realizability.
SFAS No. 121, "Accounting for the Impairment of Long Lived Assets and for
Long-Lived Assets to Be Disposed Of," which was adopted by the Company on
January 1, 1996, requires that any assets, including regulatory assets, that
are no longer probable of recovery through future revenues, be revalued based
upon future cash flows. SFAS No. 121 requires that a rate-regulated
enterprise recognize an impairment loss for the amount of costs excluded from
recovery. As of December 31, 1998, based upon the regulatory environment
within which the Company currently operates, SFAS No. 121 did not have an
impact on the Company's financial position or results of operations.
Competitive influences or regulatory developments may impact this status in
the future.
Because the Company is unable to predict what form possible future
restructuring legislation will take, it cannot predict if or to what extent
SFAS Nos. 71 and 121 will continue to be applicable in the future. In
addition, if the Company is unable to mitigate or otherwise recover stranded
costs that could arise from any potentially adverse legislation or regulation,
the Company would have to assess the likelihood and magnitude of losses
incurred under its power contract obligations.
As such, the Company cannot predict whether any restructuring legislation
enacted in Vermont or New Hampshire, once implemented, would have a material
adverse effect on the Company's operations, financial condition or credit
ratings. However, the Company's failure to recover a significant portion of
its purchased power costs, would likely have a material adverse effect on the
Company's results of operations, cash flows, ability to obtain capital at
competitive rates and ability to exist as a going concern. It is possible
that stranded cost exposure before mitigation could exceed the Company's
current total common stock equity.
Inflation The annual rate of inflation, as measured by the Consumer Price
Index, was 1.6% for 1998, 1.7% for 1997 and 3.3% for 1996. The Company's
revenues, however, are based on rate regulation that generally recognizes only
historical costs. Although the rate of inflation has eased, it continues to
have an impact on most aspects of the business.
New Accounting Pronouncements In June 1997, the FASB issued SFAS No. 130,
Reporting Comprehensive Income, effective for fiscal years beginning after
December 15, 1997. SFAS No. 130 established standards for reporting and
display of comprehensive income and its components in a full set of general-
purpose financial statements. It requires that an enterprise classify items
of other comprehensive income by their nature in a financial statement and
display the accumulated balance of other comprehensive income separately in
the equity section of a statement of financial position. The Company did not
have any material other comprehensive income items in 1997 or 1996, however,
in 1998 the Company recognized as other comprehensive income a minimum pension
liability adjustment of $0.6 million on a pre-tax basis, or $0.4 million net
of tax.
In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities. This Statement establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value.
This Statement requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. Special accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the income statement,
and requires that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15, 1999.
A company may also implement this Statement as of the beginning of any fiscal
quarter after issuance (that is, fiscal quarters beginning June 16, 1998 and
thereafter). SFAS No. 133 cannot be applied retroactively. SFAS No. 133 must
be applied to (a) derivative instruments and (b) certain derivative
instruments embedded in hybrid contracts that were issued, acquired, or
substantively modified after December 31, 1997 (and, at the company's
election, before January 1, 1998). The Company has not yet quantified the
impacts of adopting SFAS No. 133 on the financial statements and has not
determined the timing of or method of the adoption of SFAS No. 133. However,
the Statement could increase volatility in earnings and other comprehensive
income.
In April 1998, the American Institute of Certified Public Accountants
issued Statement of Position 98-5, Reporting on the Costs of Start-up
Activities (SOP 98-5). SOP 98-5 provides guidance on the financial reporting
of start-up costs and organization costs. It requires costs of start-up
activities and organization costs to be expensed as incurred and is effective
for financial statements for fiscal years beginning after December 15, 1998.
The adoption of SOP 98-5 is not expected to have a material impact on the
Company's financial position or results of operations.
In December 1998, the Emerging Issues Task Force (EITF) reached consensus
on Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and
Risk Management Activities. EITF Issue 98-10 is effective for fiscal years
beginning after December 15, 1998. EITF Issue 98-10 requires energy trading
contracts to be recorded at fair value on the balance sheet, with the changes
in fair value included in earnings. The effects of initial application of
EITF Issue 98-10 will be reported as a cumulative effect of a change in
accounting principle. Financial statements for periods prior to initial
adoption of EITF Issue 98-10 may not be restated. We have not yet quantified
the impacts of this accounting change as of January 1, 1999 on the financial
statements.
Forward Looking Statements This document contains statements that are forward
looking. These statements are based on current expectations that are subject
to risks and uncertainties. Actual results will depend, among other things,
upon general economic and business conditions, weather, the actions of
regulators, including the outcome of the litigation involving Connecticut
Valley before the FERC and the Court and the Company's pending rate case
before the PSB and associated appeal to the Vermont Supreme Court, as well as
other factors which are described in further detail in the Company's filings
with the Securities and Exchange Commission. The Company cannot predict the
outcome of any of these proceedings or other factors.
Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements and Supplementary Data
Page No.
Report of Independent Public Accountants. . . . . . . . . . . 47
Financial Statements:
Consolidated Statement of Income for each of the
three years ended December 31, 1998 . . . . . . . . . . . 48
Consolidated Statement of Cash Flows for each of
the three years ended December 31, 1998 . . . . . . . . . 49
Consolidated Balance Sheet at December 31, 1998
and 1997 . . . . . . . . . . . . . . . . . . . . . . . . . 50
Consolidated Statement of Capitalization at
December 31, 1998 and 1997 . . . . . . . . . . . . . . . . 51
Consolidated Statement of Changes in Common Stock
Equity for each of the three years ended
December 31, 1998 . . . . . . . . . . . . . . . . . . . . 52
Notes to Consolidated Financial Statements . . . . . . . . 53
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 (the Company) as of December 31, 1998 and 1997, 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, 1998.
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, 1998
and 1997 and the results of their operations and cash flows for each of the
three years in the period ended December 31, 1998 in conformity with generally
accepted accounting principles.
As discussed in Note 13, the Company has filed with the Federal Energy
Regulatory Commission a request for an exit fee mechanism to cover the
stranded costs resulting from the anticipated cancellation of the power
contract between the Company and its wholly owned subsidiary Connecticut
Valley. If the Company is unable to obtain an order authorizing the recovery
of a significant portion of the exit fee, or other appropriate stranded cost
mechanism, the Company would be required to recognize a loss under this
contract of a material amount. The Company is also involved in related
litigation in the federal courts. Additionally, on October 27, 1998, the
Company reached a settlement agreement on rates with the Vermont Public
Service Board (PSB). The agreement incorporates a disallowance of a portion
of the Company's purchased power cost under its Hydro-Quebec contracts while
the Vermont Supreme Court is reviewing the Company's claim that the PSB is
precluded from again trying the Company on certain Hydro-Quebec contract
issues. If the ultimate resolution of these proceedings is unfavorable to the
Company, the result would have a significant adverse impact on the Company and
could impact the Company's financial viability.
ARTHUR ANDERSEN LLP
Boston, Massachusetts
February 25, 1999 (except with respect
to the matter discussed in Note 18,
as to which the date is March 26,
1999)
CONSOLIDATED STATEMENT OF INCOME
(Dollars in thousands, except per share amounts)
Year Ended December 31
1998 1997 1996
Operating Revenues $303,835 $304,732 $290,801
Operating Expenses
Operation
Purchased power 184,887 171,443 154,422
Production and transmission 23,383 22,417 20,941
Other operation 44,110 40,909 38,098
Maintenance 15,613 15,333 14,918
Depreciation 16,708 16,931 17,960
Other taxes, principally property taxes 11,426 11,490 10,971
Taxes on income (283) 7,573 10,216
________ ________ ________
Total operating expenses 295,844 286,096 267,526
________ ________ ________
Operating Income 7,991 18,636 23,275
________ ________ ________
Other Income and Deductions
Equity in earnings of affiliates 3,191 3,214 3,302
Allowance for equity funds during construction 61 75 347
Other income, net 3,826 6,522 2,447
Provision for income taxes (426) (1,590) (4)
________ ________ ________
Total other income and deductions, net 6,652 8,221 6,092
________ ________ ________
Total Operating and Other Income 14,643 26,857 29,367
________ ________ ________
Interest Expense
Interest on long-term debt 9,868 9,337 9,473
Other interest 831 400 615
Allowance for borrowed funds during construction (39) (31) (163)
________ ________ ________
Total interest expense, net 10,660 9,706 9,925
________ ________ ________
Net Income Before Extraordinary Charge 3,983 17,151 19,442
Extraordinary Charge Net of Taxes - 811 -
________ ________ ________
Net Income 3,983 16,340 19,442
Preferred Stock Dividends Requirements 1,945 2,028 2,028
________ ________ ________
Earnings Available For Common Stock $ 2,038 $ 14,312 $ 17,414
======== ======== ========
Average Shares of Common Stock Outstanding 11,439,688 11,458,735 11,543,998
Basic and Diluted Share of Common Stock:
Earnings before extraordinary charge $ .18 $1.32 $1.51
Extraordinary charge - .07 -
Earnings Per Basic and Diluted Share of Common Stock $ .18 $1.25 $1.51
Dividends Paid Per Share of Common Stock $ .88 $ .88 $ .84
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)
Year Ended December 31
1998 1997 1996
Cash Flows Provided (Used) By Operating Activities
Net income $ 3,983 $16,340 $19,442
Adjustments to reconcile net income to net cash
provided by operating activities
Equity in earnings of affiliates (3,191) (3,214) (3,302)
Dividends received from affiliates 3,267 3,216 2,978
Equity in earnings from non-utility investments (6,740) (5,378) (4,251)
Distribution of earnings from non-utility
investments 4,744 4,403 3,813
Depreciation 16,708 16,931 17,960
Amortization of capital leases 1,081 1,081 1,081
Deferred income taxes and investment tax credits (5,989) (6,529) 464
Extraordinary charge - 1,198 -
Allowance for equity funds during construction (61) (75) (347)
Net deferral and amortization of nuclear
replacement energy and maintenance costs (1,657) 4,913 (1,773)
Amortization of conservation & load management
costs 5,202 7,018 5,651
Net deferral and amortization of restructuring
costs (1,075) - 327
Gain on sale of investment - (2,891) -
Gain on sale of property - (2,095) (700)
(Increase) decrease in accounts receivable and
unbilled revenues (5,465) 855 (1,076)
Increase in accounts payable 6,543 668 1,185
Increase (decrease) in accrued income taxes (3,656) 4,168 1,055
Change in other working capital items (4,094) 3,532 7,890
Change in environmental reserve 6,848 591 (2,647)
Other, net 5,295 (2,758) (4,743)
_______ _______ _______
Net cash provided by operating activities 21,743 41,974 43,007
_______ _______ _______
Investing Activities
Construction and plant expenditures (16,046) (13,841) (18,952)
Conservation and load management expenditures (2,208) (1,837) (1,589)
Return of capital 233 233 233
Proceeds from sale of investment - 3,750 -
Proceeds from sale of property - 2,624 1,050
Special deposit 2,946 2,283 (5,246)
Non-utility investments (3,046) (1,197) (2,462)
Other investments, net (251) 54 (293)
_______ _______ _______
Net cash used for investing activities (18,372) (7,931) (27,259)
_______ _______ _______
Financing Activities
Sale (repurchase) of common stock 494 (1,072) (1,042)
Short-term debt, net 24,350 (5,100) (7,740)
Long-term debt, net (20,520) (3,019) 232
Retirement of Preferred stock (1,000) (1,000) -
Common and preferred dividends paid (12,006) (12,630) (11,728)
Reduction in capital lease obligations (1,082) (1,081) (1,081)
Other (62) - 14
_______ _______ _______
Net cash used for financing activities (9,826) (23,902) (21,345)
_______ _______ _______
Net Increase (Decrease) In Cash and Cash Equivalents (6,455) 10,141 (5,597)
Cash and Cash Equivalents at Beginning of Year 16,506 6,365 11,962
_______ _______ _______
Cash and Cash Equivalents at End of Year $10,051 $16,506 $ 6,365
======= ======= =======
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized) $10,267 $ 9,476 $ 9,920
Income taxes (net of refunds) $ 9,556 $10,654 $ 8,504
Non-cash Operating, Investing and Financing Activities
Receivables purchase agreement (Note 10)
Regulatory assets (Notes 1,2 and 12)
Long-term lease arrangements (Note 14)
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEET
(Dollars in thousands)
December 31
Assets 1998 1997
Utility Plant, at original cost $469,204 $461,482
Less accumulated depreciation 160,666 151,250
________ ________
308,538 310,232
Construction work in progress 10,461 10,450
Nuclear fuel, net 948 964
________ ________
Net utility plant 319,947 321,646
________ ________
Investments and Other Assets
Investments in affiliates, at equity 26,142 26,495
Non-utility investments 35,896 30,772
Non-utility property, less accumulated depreciation 2,920 2,894
________ ________
Total investments and other assets 64,958 60,161
________ ________
Current Assets
Cash and cash equivalents 10,051 16,506
Special deposits 424 3,368
Accounts receivable, less allowance for uncollectible
accounts ($2,242 in 1998 and $1,946 in 1997) 29,224 23,166
Unbilled revenues 18,677 18,951
Materials and supplies, at average cost 3,746 3,779
Prepayments 1,881 1,464
Other current assets 9,768 4,970
________ ________
Total current assets 73,771 72,204
________ ________
Regulatory Assets 66,719 74,130
________ ________
Other Deferred Charges 4,887 3,799
________ ________
Total Assets $530,282 $531,940
======== ========
Capitalization And Liabilities
Capitalization
Common stock equity $179,182 $187,123
Preferred and preference stock 8,054 8,054
Preferred stock with sinking fund requirements 18,000 19,000
Long-term debt 90,077 93,099
Capital lease obligations 16,141 17,223
________ ________
Total capitalization 311,454 324,499
________ ________
Current Liabilities
Short-term debt 37,000 12,650
Current portion of long-term debt 6,773 24,271
Accounts payable 11,589 4,609
Accounts payable - affiliates 11,784 12,441
Accrued income taxes 2,975 6,631
Dividends declared 2,521 2,513
Nuclear decommissioning costs 4,820 6,010
Disallowed purchased power costs 7,361 -
Other current liabilities 17,403 21,646
________ ________
Total current liabilities 102,226 90,771
________ ________
Deferred Credits
Deferred income taxes 47,581 53,996
Deferred investment tax credits 6,831 7,222
Nuclear decommissioning costs 23,239 28,947
Other deferred credits 38,951 26,505
________ ________
Total deferred credits 116,602 116,670
________ ________
Commitments and Contingencies
Total Capitalization and Liabilities $530,282 $531,940
======== ========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CAPITALIZATION
(Dollars in thousands)
December 31
1998 1997
Common Stock Equity
Common stock, $6 par value, authorized 19,000,000
shares; outstanding 11,785,848 shares $ 70,715 $ 70,715
Other paid-in capital 45,318 45,295
Accumulated other comprehensive income (365) -
Treasury stock (324,717 shares and 362,447 shares,
respectively, at cost) (4,234) (4,728)
Retained earnings 67,748 75,841
________ ________
Total common stock equity 179,182 187,123
________ ________
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; 190,000 shares 18,000 19,000
Preferred stock, $25 par value, authorized
1,000,000 shares
Outstanding - none - -
Preference stock, $1 par value, authorized
1,000,000 shares
Outstanding - none - -
________ ________
Total cumulative preferred and preference stock 26,054 27,054
________ ________
Long-Term Debt
First Mortgage Bonds
9.20 % Series EE, due 1998 - 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 18,000 21,000
8.91 % Series JJ, due 2031 15,000 15,000
5.30 % Series KK, due 1998 - 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 (3.50% at December 31, 1998) 5,800 5,800
New Hampshire Industrial Development Authority Bonds
6.40%, due 2009 5,500 5,500
Connecticut Development Authority Bonds
Variable, due 2015 (3.15% at December 31, 1998) 5,000 5,000
Other, various 4,050 4,070
________ ________
96,850 117,370
Less current portion 6,773 24,271
________ ________
Total long-term debt 90,077 93,099
________ ________
Capital Lease Obligations 16,141 17,223
________ ________
Total Capitalization $311,454 $324,499
======== ========
The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCK EQUITY
(Dollars in thousands)
Accumulated
Other Other
Common Stock Paid-in Comprehensive Treasury Retained
Shares Amount Capital Income Stock Earnings Total
Balance, December 31, 1995 11,590,748 70,715 45,251 (2,628) 66,422 179,760
Treasury stock at cost (71,000) (1,028) (1,028)
Net income 19,442 19,442
Cash dividends on capital stock:
Common stock - $.40 per share (4,630) (4,630)
Common stock - $.44 per share (5,069) (5,069)
Cumulative preferred stock:
Non-redeemable (368) (368)
Redeemable (1,660) (1,660)
Amortization of preferred stock
issuance expenses 22 22
__________ _______ _______ _______ _______ _______ ________
Balance, December 31, 1996 11,519,748 70,715 45,273 - (3,656) 74,137 186,469
Treasury stock at cost (96,347) (1,072) (1,072)
Net income 16,340 16,340
Cash dividends on capital stock:
Common stock - $.88 per share (12,608) (12,608)
Cumulative preferred stock:
Non-redeemable (368) (368)
Redeemable (1,660) (1,660)
Amortization of preferred stock
issuance expenses 22 22
__________ _______ _______ _______ _______ _______ ________
Balance, December 31, 1997 11,423,401 $70,715 $45,295 - $(4,728) $ 75,841 $187,123
Treasury stock at cost 37,730 494 494
Net income 3,983 3,983
Other comprehensive income net of taxes (365) (365)
Cash dividends on capital stock:
Common stock - $.88 per share (10,131) (10,131)
Cumulative preferred stock:
Non-redeemable (368) (368)
Redeemable (1,577) (1,577)
Amortization of preferred stock
issuance expenses 23 23
__________ _______ _______ _______ _______ _______ ________
Balance, December 31, 1998 11,461,131 $70,715 $45,318 $ (365) $(4,234) $ 67,748 $179,182
========== ======= ======= ======= ======= ======== ========
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 New Hampshire Public Utilities Commission (NHPUC) and the
Federal Energy Regulatory Commission (FERC), 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," for both Central Vermont
Public Service Corporation's (Company) regulated Vermont service territory and
FERC regulated wholesale business. 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. 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. Criteria that give rise to
the discontinuance of SFAS No. 71 include (1) increasing competition that
restricts the Company's ability to establish prices to recover specific costs,
and (2) a significant change in the manner in which rates are set by
regulators from cost-based regulation to another form of regulation.
Management periodically reviews these criteria to ensure the continuing
application of SFAS No. 71 is appropriate. Based on a current evaluation of
the various factors and conditions that are expected to impact future cost
recovery, management believes that its regulatory assets are probable of
future recovery in the state of Vermont for the Company's retail business.
However, such recovery of regulatory assets is not probable in the state of
New Hampshire for Connecticut Valley.
As a result of legal and regulatory actions described in Note 13 below,
management determined that the application of regulatory accounting principles
applied to Connecticut Valley should be discontinued. As such, Connecticut
Valley has written off regulatory assets of approximately $1.3 million on a
pre-tax basis. In addition, Connecticut Valley recorded estimated total losses
of $4.3 million pre-tax for disallowed power costs of $1.6 million, and 1998
refund obligations of $2.7 million. See Note 13 below.
Unregulated Business The Company's two wholly owned non-regulated
subsidiaries, Catamount Energy Corporation (Catamount) and SmartEnergy
Services, Inc. (SmartEnergy), results of operations are included in other
income, net in the Other Income and Deductions section of the Consolidated
Statement of Income. Catamount's policy is to expense all screening,
feasibility and development expenditures. Costs incurred subsequent to
obtaining financial viability are recognized as assets subject to depreciation
or amortization in accordance with industry practice. Project viability is
obtained when it becomes probable that costs incurred will generate future
economic benefits sufficient to recover these costs.
Revenues Estimated unbilled revenues are recorded at the end of accounting
periods. Unbilled revenues of approximately $18.7 million, $18.9 million, and
$18.8 million for 1998, 1997 and 1996, respectively, are included in revenues
on the Consolidated Statement of Income. See Note 10 below.
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 3.55% of the cost of depreciable
utility plant for each of the years 1996 through 1998.
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 12. 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 9.24%,
9.38% and 8.62% for the years 1996 through 1998, respectively.
Regulatory Assets Certain costs are deferred and amortized in accordance with
authorized or expected rate-making treatment. The major components of
regulatory assets reflected in the Consolidated Balance Sheet as of
December 31, are as follows (dollars in thousands):
1998 1997
Conservation and load management $15,611 $16,236
Restructuring costs 5,087 7,677
Nuclear refueling outage costs 2,948 1,291
Income taxes 9,613 10,405
Year 2000 costs and technologies initiatives 2,204 31
Dismantling costs:
Maine Yankee nuclear power plant 15,228 17,368
Connecticut Yankee nuclear power plant 9,971 12,778
Yankee Atomic nuclear power plant 2,860 4,810
Unrecovered plant and regulatory study costs 1,875 2,042
Other regulatory assets 1,322 1,492
_______ _______
$66,719 $74,130
======= =======
During regular nuclear refueling outages, the incremental 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 C&LM and replacement energy
and maintenance costs. The net regulatory asset related to the adoption of
SFAS No. 109 is recovered through tax expense in the Company's cost of service
generally over the remaining lives of the related property. Recovery for the
unamortized dismantling costs for Yankee Atomic, Connecticut Yankee and Maine
Yankee is provided without a return on investment through mid-2000, 2007 and
2008, respectively. See Note 2 below for discussion of the costs associated
with the discontinued operations of the Yankee Atomic, Connecticut Yankee and
Maine Yankee nuclear power plants. In addition, the Company is not earning a
return on approximately $6.4 million of restructuring and other unamortized
regulatory assets which are being recovered over periods ranging from two to
33 years.
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 14, do not convey to the Company the right to use
property, plant, or equipment, they are considered executory in nature. This
accounting treatment is in contrast to the Company's commitment with respect
to the Hydro Quebec Phase I and II transmission facilities which are
considered capital leases. As such, the Company has recorded a liability for
its commitment under the Phase I and II arrangements and recognized an asset
for the right to use these facilities.
Use of Estimates The preparation of financial statements in accordance with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities,
the disclosures of contingent assets and liabilities and revenues and
expenses. Actual results could differ from those estimates.
Statement of Cash Flows The Company considers all highly liquid investments
with a maturity of three months or less when acquired to be cash equivalents.
Reclassifications Certain reclassifications have been made to prior year
Consolidated Financial Statements to conform with the 1998 presentation.
Note 2
Investments in affiliates
The Company uses the equity method to account for its investments in the
following companies (dollars in thousands):
December 31
Ownership 1998 1997
Nuclear generating companies:
Vermont Yankee Nuclear Power Corporation 31.3% $16,969 $16,866
Connecticut Yankee Atomic Power Company 2.0% 2,094 2,208
Maine Yankee Atomic Power Company 2.0% 1,578 1,560
Yankee Atomic Electric Company 3.5% 690 835
_______ _______
21,331 21,469
Vermont Electric Power Company, Inc.:
Common stock 56.8% 3,513 3,518
Preferred stock 1,298 1,508
_______ _______
$26,142 $26,495
======= =======
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 $66.7
Maine Yankee 1998 $343.9 $6.9 $ 4.3
Connecticut Yankee 1996 $426.7 $8.5 $ 5.0
Yankee Atomic 1994 $370.0 $13.0 $ 4.8
Vermont Yankee
Vermont Yankee is in the process of preparing an updated site
decommissioning cost study. Preliminary results indicate that the new
decommissioning estimate could exceed $500 million in 1998 dollars. Vermont
Yankee expects to file results of the new decommissioning study with the FERC
during the first quarter of 1999, and expects that any resulting change in
rates will be effective January 1, 2000.
Maine Yankee
On August 6, 1997, the Maine Yankee's nuclear power plant was prematurely
retired from commercial operation. The Company relied on Maine Yankee for
less than 5% of its required system capacity. Future payments for the
closing, decommissioning and recovery of the remaining investment in Maine
Yankee are estimated to be approximately $715.0 million in 1998 dollars
including a decommissioning obligation of $344.0 million.
On January 19, 1999, Maine Yankee and the active intervenors filed an
Offer of Settlement with the FERC which, if approved by the FERC, would result
in the settlement of all issues raised in the FERC proceeding, including
recovery of anticipated future payments for closing, decommissioning and
recovery of the remaining investment in Maine Yankee. Approval of the
settlement would also resolve the issues raised by the secondary purchasers,
who purchased Maine Yankee power through agreements with the original owners,
by limiting the amounts they will pay for decommissioning the Maine Yankee
plant and by settling other points of contention affecting individual
secondary purchasers. As a result, it is possible that the Company would not
be able to recover approximately $.5 million of these costs.
Connecticut Yankee
On December 4, 1996, the Connecticut Yankee Nuclear power plant was
prematurely retired from commercial operation. The Company relied on
Connecticut Yankee for less than 3.0% of its required system capacity.
On August 31, 1998, a FERC Administrative Law Judge recommended that the
owners of Connecticut Yankee, including the Company, may collect from
customers $350.0 million for decommissioning the Connecticut Yankee Nuclear
Power Plant rather than the $426.7 million requested. The Administrative Law
Judge ruling is subject to approval by the FERC Commissioners. If approved,
it is possible that the Company would not be able to recover approximately
$1.5 million of decommissioning costs through the regulatory process.
Yankee Atomic
In 1992, the Yankee Atomic nuclear power plant was retired from
commercial operation. The Company relied on Yankee Atomic for less than 1.5%
of its system capacity.
Presently, costs billed to the Company by Maine Yankee, Connecticut
Yankee and Yankee Atomic, including a provision for ultimate decommissioning
of the units, are being collected from the Company's customers through
existing retail and wholesale rate tariffs. The Company's share of remaining
costs with respect to Maine Yankee, Connecticut Yankee and Yankee Atomic's
decisions to discontinue operation, including the costs in the table above, is
estimated to be $15.2 million, $10.0 million and $2.9 million, respectively,
at December 31, 1998. These amounts are subject to ongoing review and
revisions and are reflected in the accompanying balance sheet both as
regulatory assets and nuclear decommissioning costs (current and non-current).
Although the estimated costs of decommissioning are subject to change due to
changing technologies and regulations, the Company expects that the nuclear
generating companies' liability for decommissioning, including any future
changes in the liability, will be recovered in their rates over their
operating or license lives.
The decision to prematurely retire these nuclear power plants was based
on economic analyses of the costs of operating them compared to the costs of
closing them and incurring replacement power costs over the remaining period
of the plants' operating licenses. The Company believes that based on the
current regulatory process, its proportionate share of Maine Yankee,
Connecticut Yankee and Yankee Atomic decommissioning costs will be recovered
through the regulatory process and, therefore, the ultimate resolution of the
premature retirement of the three plants has not and will not have a material
adverse effect on the Company's earnings or financial condition.
Nuclear Insurance
The Price-Anderson Act currently limits public liability from a single
incident at a nuclear power plant to $9.8 billion. Beyond that a licensee
maintains an indemnity agreement with the Nuclear Regulatory Commission (NRC),
but subject to Congressional approval. The first $200 million of liability
coverage is the maximum provided by private insurance. The Secondary
Financial Protection Program is a retrospective insurance plan providing
additional coverage up to $9.6 billion per incident by assessing $88.1 million
against each of the 109 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
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 $3.7 million of such maximum
assessment per incident per year.
Vermont Yankee
Summarized financial information for Vermont Yankee Nuclear Power
Corporation is as follows (dollars in thousands):
Earnings 1998 1997 1996
Operating revenues $195,249 $173,106 $181,715
Operating income $15,282 $13,961 $14,705
Net income $7,125 $6,834 $6,985
Company's equity in net income $2,218 $2,144 $2,193
December 31
Investment 1998 1997
Current assets $ 36,947 $ 43,106
Non-current assets 598,927 566,918
________ ________
Total assets 635,874 610,024
Less:
Current liabilities 32,250 34,138
Non-current liabilities 548,981 521,597
________ ________
Net assets $ 54,643 $ 54,289
________ ________
Company's equity in net assets $ 16,969 $ 16,866
Included in Vermont Yankee's revenues shown above are sales to the
Company of $53.1 million, $58.6 million and $59.1 million for 1996 through
1998, respectively. These amounts are reflected as purchased power net of
deferrals and amortization in the accompanying Consolidated Statement of
Income.
Velco
Vermont Electric Power Company, Inc. (Velco) and its wholly owned
subsidiary Vermont Electric Transmission Company, Inc. own and operate
transmission systems in Vermont over which bulk power is delivered to all
electric utilities in the state. Velco has entered into transmission
agreements with the state of Vermont and the electric utilities and under
these agreements bills all costs, including interest on debt and a fixed
return on equity, to the state and others using the system. These contracts
enable Velco to finance its facilities primarily through the sale of first
mortgage bonds. Included in Velco's revenues shown below are transmission
services to the Company (reflected as production and transmission expenses in
the accompanying Consolidated Statement of Income) amounting to $7.9 million,
$8.7 million and $8.8 million for 1996 through 1998, 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 1999 and will be
extended for an additional two-year term in May 1999, 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 1998 1997 1996
Transmission revenues $17,268 $18,481 $16,298
Operating income $ 2,691 $ 2,773 $2,611
Net income $ 1,153 $ 1,213 $1,216
Company's equity in net income $581 $618 $657
December 31
Investment 1998 1997
Current assets $21,678 $22,274
Non-current assets 45,980 48,281
_______ _______
Total assets 67,658 70,555
Less:
Current liabilities 21,754 30,441
Non-current liabilities 36,936 30,710
_______ _______
Net assets $ 8,968 $ 9,404
======= =======
Company's equity in net assets $ 4,811 $ 5,026
Note 3
Non-utility investments
The Company's wholly owned subsidiary, Catamount, invests through its
wholly owned subsidiaries, in non-regulated, energy-related projects.
Catamount's earnings were $3.3 million, $4.1 million and $.5 million for 1998,
1997 and 1996, respectively. Earnings for 1997 reflect a net of tax gain of
approximately $1.8 million from the sale of NW Energy Williams Lake L.P.
Certain financial information for Catamount's investments is set forth in the
table that follows (dollars in thousands):
Investment
Generating In Service December
31
Projects Location Capacity Fuel Date Ownership 1998
1997
Rumford Cogeneration Co. L.P. Maine 85MW Coal/Wood 1990 15.1% $13,273
$11,638
Ryegate Associates Vermont 20MW Wood 1992 33.1% 6,305
6,551
Appomattox Cogeneration L.P. Virginia 41MW Coal/Biomass 1982 25.3% 4,079
4,083
Black liquor
Rupert Cogeneration Partners, Ltd. Idaho 10MW Gas 1996 50.0% 1,775
1,586
Glenns Ferry Cogeneration Partners, Ltd. Idaho 10MW Gas 1996 50.0% 1,387
1,255
Fibrothetford Limited Thetford, England 38.5MW Biomass 1998 44.0% 8,556
5,238
Other 421
421
_______
_______
$35,796
$30,772
=======
=======
Catamount has entered into an option agreement granting it the right to
invest, subject to certain conditions, $1.2 million to purchase a 50% interest
in Heartlands Power Limited (Heartlands). Heartlands was formed by Rolls-
Royce Power Ventures to develop, construct and own a 98MW natural gas-fired
power station in Fort Dunlop, England. Catamount also has the right to fund a
loan to the project of $3.3 million. These option agreements expire on
June 30, 1999. Catamount currently has a $1.2 million letter of credit
outstanding to support certain of its obligations in connection with a debt
service requirement in the Appomattox Cogeneration project and aggregated
letters of credit of $11.0 million in support of construction and equity
commitments for its Gauley River Power project.
SmartEnergy, also a wholly owned subsidiary of the Company, whose purpose
is to engage in the sale of or rental of electric water heaters, energy
efficient products and other related goods and services. As of December 31,
1998, SmartEnergy has investments of $.1 million and incurred losses of
$1.5 million and $.7 million for 1998 and 1997, respectively, and earnings of
$.3 million for 1996.
Note 4
Common Stock
Through a common stock repurchase program which was suspended in 1997,
the Company purchased from time to time 324,717 shares of its common stock in
open market transactions at an average price of $13.19 per share. These
transactions are recorded as treasury stock, at cost, in the Company's
Consolidated Balance Sheet.
Note 5
Redeemable preferred stock
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. Since the Company's redeemable preferred stock was
issued in a private placement, it is not practicable to estimate the fair
value.
Note 6
Stock Option Plans
The Company has issued stock to key employees and non-employee directors
under various option plans approved in 1988, 1993, 1997 and 1998 which
authorize the granting of options with respect to 1,025,875 shares of the
Company's common stock. Options are granted at prices not less than 100% of
the fair market value at the date of the option grant. Shares available for
future grants under the 1997 and 1998 stock option plans were 204,750 at
December 31, 1998. No additional grants may be given under the 1988 and 1993
plans. Option activity during the past three years was as follows:
Average
Option Stock
Price Options
Options outstanding at December 31, 1995 $19.0972 248,500
Options exercised 13.6250 (1,000)
Options granted 14.0375 59,975
Options expired 18.1660 (7,500)
_______
Options outstanding at December 31, 1996 $18.1271 299,975
Options exercised - -
Options granted 10.9900 126,750
Options expired 20.5416 (10,500)
_______
Options outstanding at December 31, 1997 $15.8928 416,225
Options exercised 11.6505 (34,475)
Options granted 14.6286 154,500
Options expired 24.3750 (20,250)
_______
Options outstanding at December 31, 1998 $15.4649 516,000
=======
The price range of options outstanding at December 31, 1998 is $10.9375
to $24.3125. The weighted average remaining contractual life at December 31,
1998 is 6.92 years and the weighted average exercise price is $15.3437.
Exercisable options at December 31,1998 total 393,000 and the weighted average
exercise price is $14.4365.
The Company accounts for these plans under Accounting Principles Board
Opinion No. 25, under which no compensation cost has been recognized.
The Company chose the Binomial model to project an estimate of
appreciation of the underlying shares of the stock during the respective
option term. The average assumptions used were as follows:
1998 1997 1996
Volatility .1861 .1808 .1756
Risk free rate of return 6.25% 6.50% 6.25%
Dividend yield 6.57% 7.13% 6.93%
Expected life in years 5-10 5-10 5-10
Under SFAS No. 123, "Accounting for Stock-Based Compensation," all awards
granted must be recognized in compensation cost. Had compensation cost for
these plans been determined consistent with SFAS No. 123, the Company's net
income and earnings per share of common stock would have been reduced to the
following pro forma amounts as follows(dollars in thousands, except per share
amounts):
1998 1997 1996
Net Income As reported $3,983 $16,340 $19,442
Pro forma $3,930 $16,309 $19,423
Earnings per share
of common stock As reported $.18 $1.25 $1.51
Pro forma $.17 $1.25 $1.51
Note 7
Long-term debt and sinking fund requirements
The Company and its subsidiaries' long-term debt contains financial and
non-financial covenants. At December 31, 1998, with exception of a
$3.75 million loan at Connecticut Valley, the Company and its subsidiaries
were in compliance with all debt covenants related to its various debt
agreements. Due to the charge-offs discussed in Note 1 above and Note 13
below, Connecticut Valley is in violation of certain covenants in its loan
with an outstanding balance of $3.75 million. This loan will be in default 30
days after notice from the bank of the violation of the applicable covenants
unless the default is otherwise cured or waived. The notice has not yet been
tendered by the bank. There would be no cross defaults of any of the
company's or its subsidiaries' loan agreements as a result of the Connecticut
Valley loan default.
Based on issues outstanding at December 31, 1998, the aggregate amount of
long-term debt maturities and sinking fund requirements are $6.75 million,
$16.5 million, $4.0 million, $7.0 million and $10.5 million for the years 1999
through 2003, respectively. Substantially all property and plant is subject
to liens under the First Mortgage Bonds.
Financial obligations of Connecticut Valley are non-recourse to the
Company.
Note 8
Short-term debt
Utility
The Company had $37.0 million and $12.6 million of outstanding short-term
debt at December 31, 1998 and 1997, respectively, at average interest rates of
5.94% for 1998 and 6.26% for 1997.
The Company has a $50.0 million revolving credit facility with a group of
banks maturing on June 1, 1999, of which $25.0 million was outstanding at
December 31, 1998. The Company expects that borrowings will be $25.0 million
at June 1, 1999. The Company must rollover an aggregate of $16.3 million of
letters of credit between December 1999 and May 2000. In addition, the
Company has a $12.0 million accounts receivable facility which matures in
November 1999. The $50.0 million revolving credit facility and the
$16.3 million of letters of credit are subject to a second mortgage interest
in the same collateral supporting the Company's first mortgage bonds. The
$12.0 million accounts receivable facility is supported by a lien against the
Company's Vermont utility accounts receivable. The Company's ability to
extend or replace the maturing $50.0 million revolving credit facility, roll
over $16.3 million of maturing letters of credit and extend the accounts
receivable facility will be dependent in large part on a positive outcome of
the pending Hydro-Quebec Contract issues at the Vermont Supreme Court (VSC) or
progress made in power contract renegotiations. Negotiations are ongoing with
the banks to extend the maturities of these financial arrangements.
Connecticut Valley, the Company's wholly owned New Hampshire subsidiary,
maintained an $.8 million committed line of credit for its construction
program and for other corporate purposes which expired on May 31, 1998.
If the Company is unable to extend the maturities of or replace the bulk
of the debt and letters of credit facilities referenced above, it would
jeopardize the Company's ability to continue as a going concern. There can be
no assurance that the Company will be successful in extending or replacing
these credit facilities.
Financial obligations of Connecticut Valley are non-recourse to the
Company.
Non-Utility
On November 12, 1998, Catamount, a wholly owned subsidiary of the
Company, replaced its $8.0 million credit facility with a $25.0 million
revolving credit facility expiring November 11, 2002 which provides for up to
$25.0 million in revolving credit loans and letters of credit. Currently, a
$1.2 million letter of credit is outstanding to support certain of Catamount's
obligations in connection with a debt reserve requirement in the Appomattox
Cogeneration project and aggregated letters of credit of $11.0 million in
support of construction and equity commitments for its Gauley River Power
project.
SmartEnergy, also a wholly owned subsidiary of the Company, maintained a
$.5 million revolving line of credit with a bank to provide working capital
and financing assistance for investment purposes. SmartEnergy had $25,000 of
outstanding short-term debt at December 31, 1997. This line of credit was
canceled on February 9, 1998.
Financial obligations of the Company's non-utility wholly owned
subsidiaries are non-recourse to the Company.
Note 9
Financial instruments
The estimated fair values of the Company's financial instruments at
December 31, 1998 and 1997 are as follows (dollars in thousands):
1998 1997
Carrying Fair Carrying Fair
Amount Value Amount Value
Note receivable, non-utility $ - $ - $ 3,686 $ 3,888
Long-term debt $96,850 $101,776 $117,370 $124,251
The carrying amount for cash and cash equivalents and short-term debt
approximates fair value because of the short maturity of those instruments.
The fair value of the Company's 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.
The Company believes that any excess or shortfall 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 not result in a
material impact on the Company's financial position or results of operations.
Note 10
Receivables purchase agreement
Pursuant to SFAS No. 125, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities," the Company classifies
amounts transferred under its receivable purchase agreement as secured
borrowings. The facility matures on November 29, 1999, accordingly, those
amounts related to the accounts receivable facility are shown at December 31,
1998 as short-term debt. If not renegotiated or extended, repayment of the
facility will be made from the ongoing collections of the underlying accounts
receivable and unbilled revenues immediately following the maturity date. The
Company expects to renegotiate a new receivable purchase agreement in 1999.
These accounts receivable and unbilled revenues were transferred with
limited recourse. A pool of assets of approximately 3% of the accounts
receivable and unbilled revenues sold are set aside for this potential
recourse liability.
Note 11
Pension and postretirement benefits
The Company has a non-contributory trusteed pension plan covering all
employees (union and non-union). Under the terms of the pension plan,
employees are generally eligible for monthly benefit payments upon reaching
the age of 65 with a minimum of five years of service. The Company's funding
policy is to contribute, at least, the statutory minimum to a trust. The
Company is not required by its union contract to contribute to multi-employer
plans.
The projected unit credit actuarial cost method was used to compute net
pension costs and the accumulated and projected benefit obligations. The
following table sets forth the funded status of the pension plan and amounts
recognized in the Company's Balance Sheet and Statement of Income (dollars in
thousands):
December 31
1998 1997
Projected benefit obligation $63,095 $67,167
Fair value of plan assets (primarily equity
and fixed income securities) 65,602 72,101
_______ _______
Projected benefit obligation more (less)
than fair value of plan assets (2,507) (4,934)
Unrecognized net transition obligation 647 1,019
Unrecognized prior service costs (2,681) (2,466)
Unrecognized net gain 15,561 14,089
_______ _______
Accrued pension liability $11,020 $ 7,708
======= =======
1998 1997 1996
Net pension costs include the following components
Service cost $ 1,802 $ 1,802 $ 2,024
Interest cost 4,459 4,307 4,221
Expected return on plan assets (4,720) (4,756) (4,285)
Net amortization and deferral 778 140 140
_______ _______ _______
Pension costs 2,319 1,493 2,100
Less amount allocated to other accounts 228 249 411
_______ _______ _______
Net pension costs expensed $ 2,091 $ 1,244 $ 1,689
======= ======= =======
Assumptions used in calculating pension cost were as follows:
December 31
1998 1997
Weighted average discount rates 6.75% 7.00%
Expected long-term return on assets 9.50% 9.50%
Rate of increase in future compensation levels 4.00% 4.00%
The Company sponsors a defined benefit postretirement medical plan that
covers all employees who retire with ten years or more of service after age
45. The Company funds this 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 Statement of Income in
accordance with SFAS No. 106 (dollars in thousands):
December 31
1998 1997
Accumulated postretirement benefit obligation $10,757 $ 9,453
Unrecognized transition obligation (3,582) (3,838)
Unrecognized net loss (1,329) (862)
_______ _______
Accrued postretirement benefit cost 5,846 4,753
Less regulatory asset for restructuring costs 1,954 2,536
_______ _______
Effective accrued postretirement benefit
costs $ 3,892 $ 2,217
======= =======
1998 1997 1996
Net postretirement benefit cost includes the
following components
Service cost $ 194 $ 197 $ 208
Interest cost 815 716 656
Expected return on plan assets (160) (145)
(112)
Amortization of transition obligation over
a twenty-year period and of regulatory asset 837 408 408
______ ______ ______
Effective postretirement benefit cost 1,686 1,176 1,160
Less amount allocated to other accounts 209 192 217
______ ______ ______
Net postretirement benefit cost expensed $1,477 $ 984 $ 943
====== ====== ======
Assumptions used in the per capita costs of the accumulated
postretirement benefit obligation were as follows:
December 31
1998 1997
Per capita percent increase in health care costs:
Pre-65 6.50% 6.50%
Post-65 5.50% 5.50%
Weighted average discount rates 6.75% 7.00%
Rate of increase in future compensation levels 4.00% 4.00%
Long-term return on assets 8.50% 8.50%
Health care trend rates are assumed to decrease to 5.0% for pre-65 and
4.5% for post-65 for the year 2001 and thereafter.
Increasing (decreasing) the assumed health care cost trend rates by one
percentage point in each year would have resulted in an increase (decrease) of
$631,000 and $(543,000), respectively, in the accumulated postretirement
benefit obligation as of December 31, 1998, and an increase (decrease) of
about $45,000 and $(39,000), respectively, in the aggregate of the service
cost and interest cost components of net periodic postretirement benefit cost
for 1998.
The Company provides postemployment benefits consisting of long-term
disability benefits. The accumulated postemployment benefit obligation at
December 31, 1998 and 1997 of $.7 and $.9 million for 1998 and 1997,
respectively, is reflected in the accompanying balance sheet as a liability
and is offset by a corresponding regulatory asset of $.5 million for 1998 and
$.6 million for 1997. 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 post-employment benefit costs
charged to expense in 1998, 1997 and 1996, including insurance premiums, were
$118,000, $247,000 and $177,000, respectively (pre-tax).
In the third quarter of 1997, the Company offered and recorded
obligations related to a voluntary retirement and severance programs to
employees. The estimated benefit obligation for the retirement program as of
December 31, 1998 is approximately $3.8 million. This amount consists of
pension benefits and post-retirement medical benefits of $1.9 million and $1.9
million, respectively. The estimated benefit obligation for the severance
program which included termination pay as well as other costs, is about
$1.4 million as of December 31, 1998. These obligations, deferred pursuant to
a PSB Accounting Order dated September 30, 1997, are reflected in the
accompanying Consolidated Balance Sheet both as regulatory assets and deferred
credits. The unamortized balance of approximately $5.0 million at
December 31, 1998 will be amortized through December 31, 2002.
Note 12
Income taxes
The components of Federal and state income tax expense are as follows
(dollars in thousands):
Year Ended December 31
1998 1997 1996
Federal:
Current $ 5,072 $12,277 $ 7,890
Deferred (4,376) (5,420) 795
Investment tax credits, net (391) (391) (391)
_______ _______ _______
305 6,466 8,294
_______ _______ _______
State:
Current 1,060 3,027 1,866
Deferred (1,222) (718) 60
_______ _______ _______
(162) 2,309 1,926
_______ _______ _______
Total Federal and state income taxes $ 143 $ 8,775 $10,220
======= ======= =======
Federal and state income taxes charged to:
Operating expenses $ (283) $ 7,573 $10,216
Other income 426 1,590 4
Extraordinary item - (388) -
_______ _______ _______
$ 143 $ 8,775 $10,220
======= ======= =======
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
1998 1997 1996
Income before income tax $4,126 $25,115 $29,662
Federal statutory rate 35% 35% 35%
Federal statutory tax expense $1,444 $8,790 $10,382
Increases (reductions) in taxes resulting
from:
Insurance settlement - - (470)
Dividend received deduction (880) (884) (909)
Deferred taxes on plant 348 283 283
State income taxes net of Federal tax
benefit (105) 1,501 1,252
Investment credit amortization (391) (391) (391)
Other (273) (524) 73
______ ______ _______
Total income tax expense provided $ 143 $8,775 $10,220
====== ====== =======
The tax effects of temporary differences and tax carry forwards that give
rise to significant portions of the deferred tax assets and deferred tax
liabilities are presented below (dollars in thousands):
Year Ended December 31
1998 1997 1996
Deferred tax assets
Purchased power accrual $ 3,695 $ 1,925 $ -
Accruals and other reserves not
currently deductible 7,575 4,818 5,212
Deferred compensation and pension 4,295 3,655 3,562
Environmental costs accrual 3,905 1,805 2,089
_______ _______ _______
Total deferred tax assets 19,470 12,203 10,863
_______ _______ _______
Deferred tax liabilities
Property, plant and equipment 51,680 51,819 51,030
Net regulatory asset 3,974 4,301 3,358
Conservation and load management
expenditures 6,453 6,713 8,147
Nuclear refueling costs 1,219 534 2,510
Other 3,725 2,832 3,281
_______ _______ _______
Total deferred tax liabilities 67,051 66,199 68,326
_______ _______ _______
Net deferred tax liability $47,581 $53,996 $57,463
======= ======= =======
The Company received an accounting order from the PSB dated September 30,
1997. This accounting order authorized the Company to defer and amortize over
a 20-year period beginning January 1, 1998, approximately $2.0 million to
reflect the revenue requirement level of additional deferred income tax
expense resulting from the enacted Vermont Corporate income tax increase from
8.25% to 9.75% in 1997.
A valuation allowance has not been recorded, as the Company expects all
deferred income tax assets will be utilized in the future.
Note 13
Retail Rates
Vermont: The Company's practice of reviewing costs periodically will
continue and rate increases will be requested when warranted. The Company
filed for a 6.6%, or $15.4 million per annum, general rate increase on
September 22, 1997 to become effective June 6, 1998 to offset increasing costs
of providing service. Approximately $14.3 million or 92.9% of the rate
increase request was to recover scheduled contractual increases in the cost of
power the Company purchases from Hydro-Quebec. At the same time, the Company
also filed a request to eliminate the winter-summer rate differential and
price electricity the same year-round. The change would be revenue-neutral
within classes of customers and overall. Over time, customers would see a
leveling off of rates so they would pay the same per kilowatt-hour during the
winter and summer months.
Several parties in the Company's rate case sought to challenge the
Company's decision in 1991 to "lock-in" its participation in its power
purchase agreement with Hydro-Quebec as one of 14 members of the Vermont Joint
Owners (VJO) claiming that the decision of the Company to commit to the power
contract in 1991 was imprudent and that power now purchased pursuant to that
agreement is not "used and useful." The parties have also claimed that the
Company has not met a condition of the PSB's prior approval of the contract,
requiring that the Company obtain all cost effective Demand Side Management.
In response, the Company filed a motion asking the PSB to rule that any
prudence and used and useful issues were resolved in prior proceedings and
that the PSB is precluded from again trying the Company on those issues.
On April 17, 1998, the PSB issued an order generally denying the
Company's motion. Given the fact that the PSB had severely penalized another
Vermont Joint Owner (VJO) member, Green Mountain Power Corporation, in an
Order dated February 27, 1998, after finding that its decision to lock-in the
Hydro-Quebec contract was imprudent and the power purchased pursuant to that
lock-in was not used and useful, the Company concluded that it was necessary
to have the so-called preclusion issue reviewed by the V.C. before the PSB
issues a final order in the Company's 6.6% rate increase request. As such,
the Company and other parties requested that the PSB consent to the filing of
an interlocutory appeal of the PSB's decision and to a stay of the rate case
pending review by the V.C.. The Company further agreed to toll the statutory
period of time in which the PSB must act on a rate request, while the matter
is in appeal. The resolution of this matter by the V.C. is likely to involve
a remand to the PSB.
The appeal and associated stay of the rate case significantly delayed the
date that new rates would have otherwise taken effect. As a result, the
Company's earnings for 1998 were adversely affected.
In an effort to mitigate eroding earnings and cash flow prospects during
the V.C. review process, on June 12, 1998 the Company filed with the PSB a
request for a 10.7% rate increase ($24.9 million of annualized revenues)
effective March 1, 1999. This rate case proceeding supplanted the 6.6% rate
increase request referenced above that is now stayed pending a review on the
so-called preclusion issue by the V.C.. On October 27, 1998, the Company
reached an agreement with the Vermont Department of Public Service (DPS)
regarding the 10.7% rate increase request. The agreement, which was approved
by the PSB on December 11, 1998, provides for a temporary rate increase in the
Company's Vermont retail rates of 4.7% or $10.9 million on an annualized basis
beginning with service rendered January 1, 1999 and sets the Company's
authorized return on common equity in its Vermont retail business at 11%
before disallowances in connection with the Hydro-Quebec Contract. The rate
increase is temporary insofar as it is subject to adjustment upon future
resolution of the Hydro-Quebec Contract issues presently before the V.C.. The
Company anticipates a resolution of the Hydro-Quebec Contract issues before
the V.C. by the end of 1999.
The agreement incorporates a disallowance of approximately $7.4 million
for the Company's purchased power costs under the Hydro-Quebec Contract while
the V.C. reviews the PSB denial of the Company's claim that the PSB is
precluded from again trying the Company on certain Hydro-Quebec Contract
issues discussed above. Upon approval of the agreement by the PSB, the
Company, during the fourth quarter of 1998, recorded a loss of $7.4 million on
a pre-tax basis for disallowed purchased power costs representing the
Company's estimated under recovery of power costs under the Hydro-Quebec
Contract. This $7.4 million disallowance was calculated using the same
formula as contained in the rate order issued by the PSB in the Green Mountain
Power Corporation (GMP) rate case on February 28, 1998 (see additional
information below).
If the Company receives an unfavorable ruling from the V.C., and the PSB
issues a rate order adopting the methodology used to determine the temporary
Hydro-Quebec disallowance for the duration of the Hydro-Quebec Contract,
approximately $205.0 million of power costs to be incurred under that contract
would not be recoverable in rates. This would result in an immediate charge
to earnings of $205.0 million once such outcome became probable. Such an
outcome would jeopardize the ability of the Company to continue as a going
concern.
New Hampshire: In an Order dated December 31, 1997 in Connecticut
Valley's Fuel Adjustment Clause (FAC) and Purchased Power Cost Adjustment
(PPCA) docket, the NHPUC found Connecticut Valley acted imprudently by not
terminating the wholesale contract between Connecticut Valley and the Company,
notwithstanding the stays of its February 28, 1997 Orders. The NHPUC Order
further directed Connecticut Valley to freeze its current FAC and PPCA rates
(other than short term rates to be paid to certain Qualifying Facilities)
effective January 1, 1998, on a temporary basis, pending a hearing to
determine: 1) the appropriate proxy for a market price that Connecticut Valley
could have obtained if it had terminated its wholesale contract with the
Company; 2) the implications of allowing Connecticut Valley to pass on to its
customers only that market price; and 3) whether the NHPUC's final
determination on the FAC and PPCA rates should be reconciled back to
January 1, 1998 or some other date.
On January 19, 1998, Connecticut Valley and the Company filed with the
Federal District Court (Court) for a temporary restraining order to maintain
the status quo ante by staying the NHPUC Order of December 31, 1997 and
preventing the NHPUC from taking any action that (I) compromises cost-based
rate making for Connecticut Valley; (ii) interferes with the Federal Energy
Regulatory Commission's (FERC) exclusive jurisdiction over the Company's
pending application to recover wholesale stranded costs upon termination of
its wholesale power contract with Connecticut Valley; or (iii) prevents
Connecticut Valley from recovering through retail rates the stranded costs and
purchased power costs that it incurs pursuant to its FERC-authorized wholesale
rate schedule with the Company.
On February 23, 1998, the NHPUC announced in a public meeting that it
reaffirmed its finding of imprudence and designated a proxy market price for
power at 4 cents per kWh in lieu of the actual costs incurred pursuant to the
wholesale power contract with the Company. In addition, the NHPUC indicated,
subject to certain conditions which were unacceptable to the companies, that
it would permit Connecticut Valley to maintain its current rates pending a
decision in Connecticut Valley's appeal of the NHPUC Order to the
New Hampshire Supreme Court.
Based on the December 31, 1997 NHPUC Order as well as the NHPUC's
February 23, 1998 announcement, which resulted in the establishment of
Connecticut Valley's rates on a non cost-of-service basis, Connecticut Valley
no longer qualified, as of December 31, 1997, for the application of SFAS
No. 71. As a result, Connecticut Valley wrote-off all of its regulatory
assets associated with its New Hampshire retail business as of December 31,
1997. This write-off amounted to approximately $1.2 million on a pre-tax
basis. In addition, Connecticut Valley recorded a $5.5 million pre-tax loss
as of December 31, 1997 under this contract provision representing Connecticut
Valley's estimated loss on power contracts for the twelve months following
December 31, 1997.
On March 20, 1998, the NHPUC issued an order which affirmed, clarified
and modified various generic policy statements including the reaffirmation to
establish rates on the basis of a regional average announced previously in its
February 28, 1997 Final Plan. The March 20, 1998 order also addressed all
outstanding motions for rehearings or clarification relative to the policies
or legal positions articulated in the Final Plan and removed the stay covering
the Company's interim stranded cost order of April 7, 1997. In addition, the
March 20, 1998 Order imposed various compliance filing requirements.
On April 3, 1998, the Court held a hearing on the companies' motion for a
Temporary Restraining Order (TRO) and Preliminary Injunction against the NHPUC
at which time both the companies and the NHPUC presented arguments. In an
oral ruling from the bench, and in a written order issued on April 9, 1998,
the Court concluded that the companies had established each of the
prerequisites for preliminary injunctive relief and directed and required the
NHPUC to allow Connecticut Valley to recover through retail rates all costs
for wholesale power requirements service that Connecticut Valley purchases
from the Company pursuant to its FERC-authorized wholesale rate schedule
effective January 1, 1998 until further court order. Connecticut Valley
received an order from the NHPUC authorizing retail rates to recover such
costs beginning in May 1998. On April 14, 1998, the NHPUC filed a notice of
appeal and a motion for a stay of the Court's preliminary injunction. The
NHPUC's request for a stay was denied. At the same time, the NHPUC permitted
Connecticut Valley to recover in rates the full cost of its wholesale power
purchases from the Company.
Also, on April 3, 1998, the Court indicated its earlier TRO enjoining the
NHPUC's restructuring orders applied to Connecticut Valley and prohibits the
enforcement of the restructuring orders until the Court conducts a
consolidated hearing and rules on the requests for permanent injunctive relief
by plaintiff Public Service Company of New Hampshire (PSNH) and the other
utilities that have been allowed to intervene in these proceedings, including
the Company and Connecticut Valley. The plaintiffs-intervenors thereafter
filed a motion asking the Court to extend its stay of action by the NHPUC to
implement restructuring and to make clear that the stay encompasses the
NHPUC's order of March 20, 1998.
As a result of these Court orders, Connecticut Valley's 1997 charges,
described above, were reversed in the first quarter of 1998. Combined, the
reversal of these charges increased 1998 net income and earnings per share of
common stock by approximately $4.5 million and $.39, respectively.
On April 1, 1998, Citizens Bank of New Hampshire (Bank) notified
Connecticut Valley that it was in default of the Loan Agreement between the
Bank and Connecticut Valley dated December 27, 1994 and that the Bank would
exercise all of its remedies from and after May 5, 1998 in the event that the
violations were not cured. After reversing the 1997 write-offs described
above, Connecticut Valley was in compliance with the financial covenants
associated with its $3.75 million loan with the Bank. As a result,
Connecticut Valley satisfied the Bank's requirements for curing the violation.
On May 11, 1998 the NHPUC issued an order requiring Connecticut Valley to
show cause why it should not be held in contempt for its failure to meet the
compliance filing requirements of its March 20, 1998 Order. A hearing on this
matter was scheduled for June 11, 1998, which was subsequently canceled
because of the Federal Court's June 5, 1998 Order, discussed below.
On June 5, 1998, the Court issued an Order which denied the NHPUC's
motion for a stay of the Court's preliminary injunction. The Order clearly
stated that no restructuring effort in New Hampshire can move forward without
the Court's approval unless all New Hampshire utilities agree to the plan.
The Order suspended all involuntary restructuring efforts for all New
Hampshire utilities until a hearing on the merits was conducted. The NHPUC
appealed this Order to the Circuit Court of Appeals. These appeals have been
fully briefed, and the Court of Appeals conducted oral argument on October 6,
1998 discussed below.
On December 3, 1998, the United States Court of Appeals (Court of
Appeals) announced its decisions on the appeals taken by the NHPUC from the
preliminary injunctions issued by the Court. Those preliminary injunctions
had stayed implementation of the NHPUC's plan to restructure the New Hampshire
electric industry and required the NHPUC to allow Connecticut Valley to
recover through its retail rates the full cost of wholesale power obtained
from the Company.
The Court of Appeals affirmed the preliminary injunction, issued by the
Court, staying restructuring until the plaintiff utilities' claims (including
those of the Company and Connecticut Valley) are fully tried. The Court of
Appeals found that PSNH had sufficiently established that without the
preliminary injunction against restructuring it would suffer substantial
irreparable injury and that it had sufficient claims against restructuring to
warrant a full trial. The Court of Appeals also affirmed the extension of the
preliminary injunction to protect the other plaintiff utilities, including
Connecticut Valley and the Company, although it questioned whether the other
utilities had as strong of arguments against restructuring as PSNH because
they did not have formal agreements with the State similar to PSNH's Rate
Agreement. The Court of Appeals stated that if the Court awards the utilities
permanent injunctive relief against restructuring after the case is tried,
then it must explain why the other utilities are also entitled to such relief.
The NHPUC filed a petition for rehearing on December 17, 1998. The Court of
Appeals denied the petition on January 13, 1999.
The Court of Appeals reversed the Court's preliminary injunction
requiring the NHPUC to allow Connecticut Valley to recover in retail rates the
full cost of the power it buys from the Company. Although the Court of
Appeals found that Connecticut Valley and the Company had made a strong
showing of irreparable injury to justify the preliminary injunction, it
concluded that Connecticut Valley's and the Company's claims did not have a
sufficient probability of success to warrant such preliminary relief. The
Court of Appeals explained that the filed-rate doctrine preserving the
exclusive jurisdiction of the FERC over wholesale power rates did not prevent
the NHPUC from deciding whether Connecticut Valley's power purchases from the
Company were prudent given alternative available sources of wholesale power.
The Court of Appeals then stated that Connecticut Valley's sales could be
reduced to the level prevailing on December 31, 1997. However, the Court of
Appeals also stated that if a reduction of existing rates were ordered "it
will be time enough to consider whether they are precluded from the Court's
injunction against the Final Plan or on other grounds."
On December 17, 1998, Connecticut Valley and the Company filed a petition
for rehearing on the grounds that the Court of Appeals had not given
sufficient weight to the Court's factual findings and that the Court of
Appeals had misapprehended both factual and legal issues. Connecticut Valley
and the Company also asked that the entire Court of Appeals, rather than only
the three-judge appellate panel that had issued the December 3 decision,
consider their petition for rehearing. On January 13, 1999, the Court of
Appeals denied the petition for rehearing.
Connecticut Valley and the Company then requested the Court of Appeals to
stay the issuance of its mandate until the companies file a petition of
certiorari to the United States Supreme Court and the Supreme Court acts on
the petition.
On January 22, 1999, the Court of Appeals denied the request. However,
the Court of Appeals granted a 21-day stay to enable the Company to seek a
stay pending certiorari from the Circuit Justice of the Supreme Court. On
February 11, 1999, the Company and Connecticut Valley filed a petition for a
writ of certiorari with the United States Supreme Court and a motion to stay
the effect of the Court of Appeals' decision while the case was pending in the
Supreme Court. The motion for a stay was addressed to Justice Souter who is
responsible for such motions pertaining to the Court of Appeals for the First
Circuit. On February 18, 1999, Justice Souter denied the stay pending the
petition for certiorari.
On November 24, 1998, Connecticut Valley filed with the NHPUC its annual
FAC/PPCA rates to be effective January 1, 1999. On January 4, 1999, the NHPUC
issued an Order allowing Connecticut Valley to increase the proposed FAC rate
of $.008 per kWh and the proposed PPCA rate of $.01000 per kWh, on a temporary
basis, effective on all bills rendered on or after January 1, 1999. In
addition, the NHPUC also ordered Connecticut Valley to pay refunds plus
interest to its retail customers for any overcharges collected as a result of
the April 9, 1998 Court Order, which are included in the estimated total
losses of $4.3 million discussed below.
As a result of legal and regulatory actions discussed above, Connecticut
Valley no longer qualifies for the application of SFAS No. 71, and wrote-off
all its regulatory assets associated with its New Hampshire retail business
estimated at approximately $1.3 million on a pre-tax basis. In addition,
Connecticut Valley recorded estimated total losses of $4.3 million pre-tax for
disallowed power costs of $1.6 million and 1998 refund obligations of
$2.7 million. Company management, however, continues to believe that the
NHPUC's actions are illegal and unconstitutional and will present its
arguments in the appropriate forum.
The pre-tax losses described above resulted in Connecticut Valley
violating applicable covenants in its outstanding loan, which if not waived or
renegotiated, allows Connecticut Valley's lender the right to accelerate the
repayment of a $3.75 million loan with Connecticut Valley.
At a status conference on February 25, 1999, the Court indicated that it
would not establish a trial date on the Company and Connecticut Valley's
request for a permanent injunction until all pending motions, including a
motion to dissolve the stay of restructuring activities filed by the NHPUC,
and motions for summary judgement filed by the NHPUC, the Company and other
parties were heard and decided. Such an injunction, if granted, could require
the NHPUC to allow Connecticut Valley to recover the full cost of the
wholesale power obtained from the Company through its retail rates. However,
the Company cannot predict the outcome of this or any of the other related
litigation.
On June 25, 1997, the Company filed with the FERC a notice of termination
of its power supply contract with Connecticut Valley, conditional upon the
Company's request to impose a surcharge on the Company's transmission tariff
to recover the stranded costs that would result from the termination of its
contract with Connecticut Valley. The amount requested was $44.9 million plus
interest at the prime rate to be recovered over a ten-year period. In its
Order dated December 18, 1997 in Docket No. ER97-3435-000, the FERC rejected
the Company's proposed stranded cost surcharge mechanism but indicated that it
would consider an exit fee mechanism for collecting stranded costs. The FERC
also rejected the Company's arguments concerning the applicability of stated
FERC policies regarding retail stranded costs, multi-state regulatory gaps and
the implications of state restructuring initiatives. The Company filed a
motion seeking rehearing of the FERC's December 18, 1997 Order which was
denied. Thereafter, the Company appealed the FERC decision to the Court of
Appeals for the District of Columbia circuit. In addition, and in accordance
with the December 18, 1997 FERC Order, on January 12, 1998 the Company filed a
request with the FERC for an exit fee mechanism to collect $44.9 million in a
lump sum, or in installments with interest at the prime rate over a ten-year
period, to cover the stranded costs resulting from the cancellation of
Connecticut Valley's power contract with the Company.
On March 11, 1998, the FERC issued an order accepting for filing the
Company's request for an exit fee effective March 14, 1998, and set hearings
to determine: whether Connecticut Valley will become an unbundled
transmission customer of the Company, the Company's expectation as to the
period of time it would serve Connecticut Valley, and the allowable amount of
the exit fee. The FERC also rejected the Company's June 25, 1997 notice of
termination indicating that the notice can be resubmitted when the power
contract is proposed to be terminated.
On April 28, 1998, the Company filed its case-in-chief before the FERC
updating the amount of the exit fee to $54.9 million which was subsequently
amended to $50.0 million in a lump sum, describing all of the ways Connecticut
Valley will become an unbundled transmission customer of the Company
subsequent to termination, and establishing the expected period of service
based upon the date of termination, whenever that occurs, and the weighted
average service life of its commitments to power resources to serve
Connecticut Valley. Had termination taken effect on January 1, 1998 this
expectation period would have equaled nineteen years.
On August 4 and 5, 1998 Phase 1 hearings were held at the FERC on the
issue of whether Connecticut Valley will become an unbundled transmission
customer of the Company. Subsequent to those hearings, the parties agreed to
go on to hearings on the Phase 2 issues (addressing the allowable amount of
the exit fee) without a preliminary determination from the Administrative Law
Judge or the FERC on the Phase 1 issues. The Company submitted supplemental
testimony on Phase 2 issues in December 1998. The matter is scheduled for
hearing later this year.
If the Company is unable to obtain an order authorizing the full recovery
amount of the exit fee, or other appropriate mechanism, the Company would be
required to recognize a loss under this contract totaling approximately
$60.0 million on a pre-tax basis. Furthermore, the Company would be required
to write-off approximately $4.0 million in regulatory assets associated with
its wholesale business on a pre-tax basis. Conversely, even if the Company
obtains a FERC order authorizing the updated requested exit fee, Connecticut
Valley would be required to recognize a loss under this contract of
approximately $50.0 million on a pre-tax basis unless Connecticut Valley has
obtained an order by the NHPUC or other appropriate body directing the
recovery of those costs in Connecticut Valley's retail rates. Either of these
reasonably possible outcomes could occur during calendar year 1999.
The Company has initiated and will continue to work for a negotiated
settlement with parties to the New Hampshire restructuring proceeding and the
NHPUC. On September 14 and 15, 1998 the Company participated in a settlement
conference with an Administrative Law Judge assigned for the settlement
process at the FERC and the parties to the Company's exit fee filing. An
adverse resolution would have a material adverse effect on the Company's
results of operations, cash flows, and ability to obtain capital at
competitive rates. However, the Company cannot predict the ultimate outcome
of this matter.
On July 23, 1996 Connecticut Valley filed with the NHPUC for an 8.8% or
approximately $1.6 million base rate increase to become effective
September 22, 1996. The increase was to recover increased operating costs and
costs of improvements to the electric system. As part of the permanent rate
increase, Connecticut Valley also requested a temporary rate increase of 5.4%
or approximately $.9 million. The NHPUC granted Connecticut Valley a
temporary rate increase of 5.4% effective with bills rendered October 1, 1996.
On January 21, 1997, Connecticut Valley and the NHPUC Staff reached a
settlement in principle regarding the permanent rate increase. The
settlement, approved by the NHPUC, provided for a 6.4% permanent rate increase
and set Connecticut Valley's allowed return on common equity at 10.2%. A 2.2%
temporary billing surcharge was also approved by the NHPUC to recover
recoupment revenues for the period October 1, 1996 and March 30, 1997 and to
recover rate case expenses. The temporary billing surcharge was effective
during the period April 1 through November 30, 1997, when off-peak rates were
in effect. As approved by the NHPUC, this billing surcharge resumed on
March 1, 1998 to recover expenses incurred in connection with the pilot
program.
Note 14
Commitments and contingencies
The Company's power supply is acquired from a number of sources including
its own generating units, jointly owned units, long-term contracts and short-
term purchases. The cost of power obtained from sources other than wholly and
jointly owned units, including payments required to be made whether or not
energy is received by the Company, is reflected as Purchased power in the
Consolidated Statement of Income.
Through its investments in four nuclear generating companies, three of
which (Maine Yankee, Connecticut Yankee and Yankee Atomic) are permanently
shut down, the Company is entitled to receive power from those nuclear units.
See Note 2 for a discussion of the Company's obligations related to its
investment in nuclear generating companies. The Company is also a joint owner
of the Millstone Unit #3 (Unit #3) nuclear generating plant.
Through Velco, the Company purchased power from Merrimack #2, a coal-
fired generating plant owned by Northeast Utilities (NU), under a thirty-year
contract which expired April 30, 1998. Under this contract the Company was
obligated to make capacity payments which amounted to approximately
$4.6 million, $4.5 million and $1.8 million for 1996 through 1998,
respectively. Pursuant to the contract, as amended, Velco agreed to reimburse
PSNH, in the proportion which the Velco quota bears to the demonstrated net
capability of the plant, for all fixed costs of the unit and operating costs
of the unit incurred by PSNH, which were reasonable and cost-effective for the
remaining term of the Velco contract. In early 1998, PSNH took the Merrimack
Unit #2 facility off line, shut it down and commenced a maintenance outage.
In February, March and April of 1998, PSNH billed Velco for costs to complete
the maintenance outage. Velco disputes the validity of a portion of the
charges on grounds that the maintenance performed at the unit was to extend
the life of the Merrimack plant beyond the term of the Velco contract and that
the charges in connection with said investments were not reasonable and
cost-effective for the remaining term of the Velco contract. The Company estimates
the portion of the disputed charges allocable to the Company could be as much
as $1.0 million on a pre-tax basis.
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
1998 the Company purchased 212,702 MWH of which 154,832 MWH is associated with
the Vermont Electric Power Producers and 38,283 MWH with the New
Hampshire/Vermont Solid Waste Plant owned by Wheelabrator Claremont Company,
L.P. The Company expects to purchase approximately 203,000 MWH of small power
output in each year 1999 through 2003. Based on the forecast level of
production, the total commitment in the next five years to purchase power from
these qualifying facilities is estimated to be $113.7 million.
The Company will receive varying amounts of capacity and energy from
Hydro-Quebec under the VJO contract during the 1999 to 2016 period. Related
contracts were negotiated between the Company and Hydro-Quebec which in effect
alter the terms and conditions contained in the VJO contract, reducing the
overall power requirements and cost of the original contract.
The average annual amount of capacity that the Company will purchase
through October 31, 2016 is 132 MW. The total commitment to purchase power
under these contracts on a nominal basis is approximately $1.0 billion net of
power sellbacks over the contract term. In February 1996, the Company reached
an agreement with Hydro-Quebec which lowered the 1997 cost of power by
$5.8 million. As part of this agreement, the Company delivers to NEPOOL under
existing firm energy contracts or joint marketing activities 54 MW of Phase II
transmission capacity for a five-year period which began July 1, 1996 through
June 30, 2001.
In the early phase of the VJO contract, two sellback contracts were
negotiated, the first delaying the purchase of 25 MW of capacity and
associated energy, the second reducing the net purchase of Hydro-Quebec power.
In 1994, the Company negotiated a third sellback arrangement whereby the
Company receives an effective discount on up to 70 MW of capacity starting in
November 1995 for the 1996 contract year (declining to 30 MW in the 1999
contract year). In exchange for this sellback, Hydro-Quebec has the right to
reduce capacity deliveries by up to 50 MW beginning as early as 2004 until
2015, including the use of a like amount of the Company's Phase I/II facility
rights and the ability to reduce the amounts of energy delivered for five
years during a fifteen-year term beginning in 2000.
There are specific contractual step up provisions that provide that in
the event any VJO member fails to meet its obligation under the contract with
Hydro-Quebec, the balance of the VJO participants, including the Company, will
"step up" to the defaulting party's share on a pro-rata basis. As of
December 31, 1998 the Company's VJO obligation is approximately 46% or
$1.0 billion on a nominal basis over the contract ending in 2016. The total
VJO contract obligation in a nominal basis over the term of the contract is
approximately $2.3 billion.
During January 1998, a significant ice storm affected parts of New
England and the Province of Quebec, Canada. This storm specifically damaged
major components of the Hydro-Quebec transmission system over which power is
supplied to Vermont under the VJO contract with Hydro-Quebec. This resulted
in an interruption of a significant portion of scheduled contractual power
deliveries into Vermont. The ice storm's effect on Hydro-Quebec's
transmission system caused the VJO to examine Hydro-Quebec's overall
reliability and ability to deliver energy in the future. That review has
prompted the VJO to initiate an arbitration proceeding, the end result of
which may be the termination of the Contract. By way of the arbitration, the
VJO is also seeking to recover capacity payments made during the period of
non-delivery.
Joint-ownership The Company's ownership interests in jointly owned generating
and transmission facilities are set forth in the table that follows and
recorded in the Company's Consolidated Balance Sheet (dollars in thousands):
Fuel In Service MW December 31
Type Ownership Date Entitlement 1998
1997
Generating plants:
Wyman #4 Oil 1.78% 1978 11 $ 3,347 $
3,344
Joseph C. McNeil Various 20.00% 1984 11 15,093
15,014
Millstone Unit #3 Nuclear 1.73% 1986 20 75,444
75,365
Highgate transmission
facility 47.35% 1985 13,930
12,984
________
________
107,814
106,707
Accumulated depreciation 37,934
34,163
________
________
$ 69,880 $
72,544
======= =======
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 Unit #3. Based on a 1997 study, the total estimated
obligation at December 31, 1998 was approximately $559.6 million and the
funded obligation was about $187.7 million. The Company's share for the total
obligation and funded obligation was approximately $9.7 million and
$3.2 million, respectively.
Environmental The Company is engaged in various operations and activities
which subject it to inspection and supervision by both federal and state
regulatory authorities including the United States Environmental Protection
Agency (EPA). It is Company policy to comply with all environmental laws.
The Company has implemented various procedures and internal controls to assess
and assure compliance. If non-compliance is discovered, corrective action is
taken. Based on these efforts and the oversight of those regulatory agencies
having jurisdiction, the Company believes it is in compliance, in all material
respects, with all pertinent environmental laws and regulations.
Company operations occasionally result in unavoidable, inadvertent
releases of regulated substances or materials, for example the rupture of a
pole mounted transformer, or a broken hydraulic line. Whenever the Company
learns of such a release, the Company responds in a timely fashion and in a
manner that complies with all federal and state requirements. Except as
discussed in the following paragraphs, the Company is not aware of any
instances where it has caused, permitted or suffered a release or spill on or
about its properties or otherwise which is likely to result in any material
environmental liabilities to the Company.
The Company is an amalgamation of more than 100 predecessor companies.
Those companies engaged in various operations and activities prior to being
merged into the Company. At least two of these companies were involved in the
production of gas from coal to sell and distribute to retail customers at
three different locations. These activities were discontinued by the Company
in the late 1940's or early 1950's. The coal gas manufacturers, other
predecessor companies, and the Company itself may have engaged in waste
disposal activities which, while legal and consistent with commercially
accepted practices at the time, may not meet modern standards and thus
represent potential liability.
The Company continues to investigate, evaluate, monitor and, where
appropriate, remediate contaminated sites related to these historic
activities. The Company's policy is to accrue a liability for those sites
where costs for remediation, monitoring and other future activities are
probable and can be reasonably estimated. As part of that process, the
Company also researches the possibility of insurance coverage that could
defray any such remediation expenses. For related information see Legal
Proceedings below.
Cleveland Avenue Property The Company's Cleveland Avenue property located in
the City of Rutland, Vermont, a site where one of its predecessors operated a
coal-gasification facility and later the Company sited various operations
functions. Due to the presence of coal tar deposits and Polychlorinated
Biphenyl (PCB) contamination and uncertainties as to potential off-site
migration of those contaminants, the Company conducted studies in the late
1980's and early 1990's to determine the magnitude and extent of the
contamination. After completing its preliminary investigation, the Company
engaged a consultant to assist in evaluating clean-up methodologies and
provide cost estimates. Those studies indicated the cost to remediate the
site would be approximately $5.0 million. This was charged to expense in the
fourth quarter of 1992. Site investigation continued over the next several
years.
In January of 1995, the Company was formally contacted by the EPA asking
for written consent to conduct a site evaluation of the Cleveland Avenue
property. That evaluation has been completed. The Company does not believe
the EPA's evaluation changes its potential liability so long as the State
remains satisfied that reasonable progress continues to be made in remediating
the site and retains oversight of the process.
In 1995, as part of that process, the Company's consultant completed its
risk assessment report and submitted it to the State of Vermont for review.
The State generally agreed with that assessment but expressed a number of
concerns and directed the Company to collect some additional data. The
Company has addressed almost all of the concerns expressed by the State and
continues to work with the State in a joint effort to develop a mutually
acceptable solution.
The Company selected a consulting/engineering firm to collect the
additional data requested by the State and develop and implement a remediation
plan for the site. That firm has begun work at the site. It has collected
the additional data requested by the State and will use all the data gathered
to date to formulate a comprehensive remediation plan. The additional data
gathered to date has not caused the Company to alter its original estimate of
the likely cost of remediating the site.
Brattleboro Manufactured Gas Facility From the early to late 1940's, the
Company owned and operated a manufactured gas facility in Brattleboro,
Vermont. The Company recently received a letter from the State of
New Hampshire asking the Company to conduct a scoping study in and around the
site of the former facility. The Company is in the process of responding to
the State's request. The Company's response will include the identification of
a qualified consultant to do the scoping study and a search for other
Potential Responsible Parties (PRPs). At this time the Company has not
finalized an estimate of its potential liability at this site.
PCB, Inc. In August 1995, the Company received an Information Request from
the EPA pursuant to a Superfund investigation of two related sites, located in
Kansas and in Missouri (the Sites). During the mid-1980's, these Sites,
operated by PCB Treatment, Inc., received materials containing PCBs from
hundreds of sources, including the Company. According to the EPA, more than
1,200 parties have been identified as PRPs. The Company has complied with the
information request and will monitor EPA activities at the Sites. In December
1996, the Company received an invitation to join a PRP steering committee.
The Company has not yet decided whether joining that committee would be in its
best interest. That committee has estimated the Company's pro rata share of
the waste sent to the Sites to be 0.42%. The committee estimates that the
Sites' remediation will cost between $5 million and $40 million. Based on
this information, the Company does not believe that the Sites represent the
potential for a material adverse effect on its financial condition or results
of operations.
The Company is not subject to any pending or threatened litigation with
respect to any other sites that have the potential for causing the Company to
incur material remediation expenses, nor has the EPA or other federal or state
agency sought contribution from the Company for the study or remediation of
any such sites.
In 1996, the Company filed a lawsuit in federal court against a number of
insurance companies. In its complaint, the Company alleged that general
liability policies issued by the insurers provide coverage for all expenses
incurred or to be incurred by the Company in conjunction with, among others,
the Cleveland Avenue Property. Settlements were reached with all of the
defendants. The settlements varied with respect to the scope of the release
granted by the Company.
A reserve of $9.9 million has been established representing management's
best estimate of the costs to remediate the 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 $66.4 million of retained earnings was not subject to dividend
restriction at December 31, 1998.
Leases and support agreements The Company participated with other electric
utilities in the construction of the Phase I Hydro-Quebec transmission
facilities in northeastern Vermont, which were completed at a total cost of
approximately $140 million. Under a support agreement relating to the
Company's participation in the facilities, the Company is obligated to pay its
4.42% share of Phase I Hydro-Quebec capital costs over a 20-year recovery
period through and including 2006. The Company also participated in the
construction of Phase II Hydro-Quebec transmission facilities constructed
throughout New England, which were completed at a total cost of approximately
$487 million. Under a similar support agreement, the Company is obligated to
pay its 5.132% share of Phase II Hydro-Quebec capital costs over a
25-year recovery period through and including 2015. All costs under these
support agreements are recorded as purchased transmission expense in
accordance with the Company's rate-making policies. Future minimum payments
will be approximately $3.0 million for each year from 1999 through 2015 and
will decline thereafter. The Company's shares of the net capital cost of
these facilities, totaling approximately $17.2 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, 1998, are not material. Total rental expense entering into
the determination of net income, consisting principally of vehicle and
equipment rentals, was approximately $3.2 million for 1996, $3.1 million for
1997 and $3.4 million for 1998.
Legal proceedings As discussed above, on July 29, 1996, the Company filed a
Declaratory Judgment action in the United States District Court for the
District of Vermont. The Complaint named as defendants a number of insurance
companies that issued policies to the Company dating from the mid 1940s to the
late 1980s. The Company asserted that policies issued by defendants provide
coverage for all defense and remediation costs associated with the Cleveland
Avenue property and other sites. Settlement has been reached with all
defendants. See Environmental above for related disclosures.
On August 7, 1997, the Company and eight other non-operating owners of
Unit #3 filed a demand for arbitration with Connecticut Light and Power
Company and Western Massachusetts Electric Company and lawsuits against NU and
its trustees. The arbitration and lawsuits seek to recover costs associated
with replacement power, operation and maintenance costs and other costs
resulting from the extended shutdown of Unit #3. The non-operating owners
claim that NU and two of its wholly owned subsidiaries failed to comply with
NRC's regulations, failed to operate the facility in accordance with good
operating practice and attempted to conceal their activities from the non-
operating owners and the NRC.
In addition to the proceedings described herein, the Company is involved
in litigation in the normal course of business which the Company does not
believe will have a material adverse effect on the financial position or
results of operations.
Note 15
New Accounting Pronouncements
In June 1997, the FASB issued SFAS No. 130, Reporting Comprehensive
Income, effective for fiscal years beginning after December 15, 1997. SFAS
No. 130 established standards for reporting and display of comprehensive
income and its components in a full set of general-purpose financial
statements. It requires that an enterprise classify items of other
comprehensive income by their nature in a financial statement and display the
accumulated balance of other comprehensive income separately in the equity
section of a statement of financial position. The Company did not have any
material other comprehensive income items in 1997 or 1996, however, in 1998
the Company recognized as other comprehensive income a minimum pension
liability adjustment of $0.6 million on a pre-tax basis, or $0.4 million net
of tax.
In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities. This Statement establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value.
This Statement requires that changes in the derivative's fair value be
recognized currently in earnings unless specific hedge accounting criteria are
met. Special accounting for qualifying hedges allows a derivative's gains and
losses to offset related results on the hedged item in the income statement,
and requires that a company must formally document, designate, and assess the
effectiveness of transactions that receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15, 1999.
A company may also implement this Statement as of the beginning of any fiscal
quarter after issuance (that is, fiscal quarters beginning June 16, 1998 and
thereafter). SFAS No. 133 cannot be applied retroactively. SFAS No. 133 must
be applied to (a) derivative instruments and (b) certain derivative
instruments embedded in hybrid contracts that were issued, acquired, or
substantively modified after December 31, 1997 (and, at the company's
election, before January 1, 1998). The Company has not yet quantified the
impacts of adopting SFAS No. 133 on the financial statements and has not
determined the timing or method of the adoption of SFAS No. 133. However, the
Statement could increase volatility in earnings and other comprehensive
income.
In April 1998, the American Institute of Certified Public Accountants
issued Statement of Position 98-5, Reporting on the Costs of Start-up
Activities (SOP 98-5). SOP 98-5 provides guidance on the financial reporting
of start-up costs and organization costs. It requires costs of start-up
activities and organization costs to be expensed as incurred and is effective
for financial statements for fiscal years beginning after December 15, 1998.
The adoption of SOP 98-5 is not expected to have a material impact on the
Company's financial position or results of operations.
In December 1998, the Emerging Issues Task Force (EITF) reached consensus
on Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and
Risk Management Activities. EITF Issue 98-10 is effective for fiscal years
beginning after December 15, 1998. EITF Issue 98-10 requires energy trading
contracts to be recorded at fair value on the balance sheet, with the changes
in fair value included in earnings. The effects of initial application of
EITF Issue 98-10 will be reported as a cumulative effect of a change in
accounting principle. Financial statements for periods prior to initial
adoption of EITF Issue 98-10 may not be restated. The Company has not yet
quantified the impacts of this accounting change as of January 1, 1999 on the
financial statements.
Note 16
Segment Reporting
The Company adopted SFAS No.131,"Disclosures about Segments of an
Enterprise and Related Information," effective for financial statements for
periods beginning after December 15, 1997. SFAS No. 131 establishes standards
for reporting information about operating segments in annual financial
statements and requires selected information about operating segments in
interim financial reports issued to stockholders. It also establishes
standards for related disclosures about products and services, and geographic
areas. Operating segments are defined as components of an enterprise about
which separate financial information is available that is evaluated regularly
by the chief operating decision maker, or decision making group, in deciding
how to allocate resources and in assessing performance. The Company's chief
operating decision making group is the Board of Directors, which is comprised
of nine Directors including the Chairman of the Board and the Company's
President and Chief Executive Officer. The operating segments are managed
separately because each operating segment represents a different retail rate
jurisdiction or offers different products or services.
The Company's reportable operating segments include Central Vermont
Public Service Corporation (Central Vermont) which engages in the purchase,
production, transmission, distribution and sale of electricity in Vermont;
Connecticut Valley Electric Company Inc. (Connecticut Valley) which
distributes and sells electricity in parts of New Hampshire; and Catamount
Energy Corporation (Catamount) which invests in non-regulated, energy-supply
projects. Connecticut Valley, while managed on an integrated basis with
Central Vermont, is presented separately because of its separate and distinct
regulatory jurisdiction. Other operating segments include segments below the
quantitative threshold for separate disclosure. These operating segments are
SmartEnergy Services, Inc. which markets energy-saving products, pursues
retail alliances to market energy and related products and services and
engages in the sale of or rental of electric water heaters, and C. V. Realty,
Inc., a real estate company whose purpose is to own, acquire, buy, sell and
lease real and personal property and interests therein related to the utility
business.
The accounting policies of the operating segments are the same as those
described in the summary of significant accounting policies. Intersegment
revenues include sales of purchased power to Connecticut Valley and revenues
for support services to Connecticut Valley, Catamount and SmartEnergy. These
intersegment sales and services for each jurisdiction are based on actual
rates or current costs. The Company evaluates performance based on stand
alone operating segment net income. Financial Information by industry segment
for the three years ended December 31, 1998, is as follows (dollars in
thousands):
Reclassifications
Central Vermont Connecticut Valley & Consolidating
1998 Vermont New Hampshire Catamount All Other(1) Entries Consolidated
Revenues from external
customers $285,007 $18,933 $ 412 $ 7,184 $ 7,701 $303,835
Intersegment revenues 12,655 - - - 12,655 -
Depreciation & other (2) 19,811 442 41 357 398 20,253
Non-Recurring Items:
Reversal of estimated loss
on power contracts (3) - 5,500 - - - 5,500
Estimated loss on power
contracts (3) - (1,586) - - - (1,586)
Purchase power disallowance (7,361) - - - - (7,361)
Taxes on income (682) 399 1,914 (1,082) 832 (283)
Operating income 7,015 1,107 (3,689) (1,643) (5,201) 7,991
Equity income-affiliates (4) 3,191 - - - - 3,191
Other income (expenses), net 1,343 22 490 95 (1,511) 3,461
Interest expense, net 10,024 387 276 1 28 10,660
Net income (loss) 1,525 742 3,265 (1,549) - 3,983
Investments in affiliates,
at equity 26,142 - - - - 26,142
Total assets 473,879 11,803 45,616 42,089 43,105 530,282
Capital expenditures 15,497 549 - - - 16,046
1997
Revenues from external
customers $285,102 $19,635 $ 348 $ 1,802 $ 2,155 $304,732
Intersegment revenues 10,818 - - - 10,818 -
Depreciation & other (2) 26,733 442 49 358 407 27,175
Non-Recurring Items:
Estimated loss on power
contracts (3) - (5,500) - - - (5,500)
Extraordinary charge,
net of taxes - 811 - - - 811
Sale of Non-Utility Assets 2,118 - 2,891 - - 5,009
Taxes on income 9,177 (1,605) 2,097 (537) 1,559 7,573
Operation income (loss) 21,364 (2,597) (4,701) (821) (5,391) 18,636
Equity income-affiliates (4) 3,214 - - - - 3,214
Other income (expenses), net 1,561 8 3,453 35 50 5,007
Interest expense, net 9,259 409 76 - 38 9,706
Net income (loss) 16,880 (3,807) 4,054 (787) - 16,340
Investments in affiliates,
at equity 26,495 - - - - 26,495
Total assets 481,971 11,648 41,215 2,967 5,861 531,940
Capital expenditures 13,220 621 - - - 13,841
1996
Revenues from external
customers $272,201 $18,607 $ 933 $ 1,862 $ 2,802 $290,801
Intersegment revenues 10,905 - - - 10,905 -
Depreciation & other (2) 21,409 429 42 377 419 21,838
Non-Recurring Items:
Insurance proceeds 1,330 - - - - 1,330
Taxes on income 10,261 (45) (202) 178 (24) 10,216
Operating income (loss) 23,189 230 (3,247) 270 (2,833) 23,275
Equity income-affiliates (4) 3,302 - - - - 3,302
Other income (expenses), net 1,814 31 (443) 9 (1,379) 2,790
Interest expense, net 9,537 333 93 - 38 9,925
Net income (loss) 18,767 (72) 468 279 - 19,442
Investments in affiliates,
at equity 26,630 - - - - 26,630
Total assets 453,943 12,244 37,637 2,973 3,829 502,968
Capital expenditures 18,188 764 - - - 18,952
(1) Includes segments below the quantitative threshold for separate disclosure.
(2) Includes net deferral and amortization of nuclear replacement energy and maintenance costs (included in
Purchased power) and amortization of conservation and load management costs (included in Other operation
expenses) in the accompanying Consolidated Statement of Income.
(3) Included in Purchased power in the accompanying Consolidated Statement of Income.
(4) See Note 2 herein for Central Vermont's investments in affiliates.
Note 17
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
1998
Operating revenues $83,958 $66,406 $69,522 $83,949 $303,835
Operating income (loss) $10,679 $(4,079) $ 931 $ 460 $ 7,991
Net income (loss) $10,264 $(5,452) $ (229) $ (600) $ 3,983
Earnings (losses) per
share of common stock $ .86 $(.52) $(.06) $(.10) $ .18
1997
Operating revenues $88,494 $65,442 $67,990 $82,806 $304,732
Operating income (loss) $14,140 $ (885) $ 1,178 $ 4,203 $ 18,636
Net income (loss) $14,319 $(1,855) $ 2,065 $ 1,811 $ 16,340
Earnings (losses) per
share of common stock $1.20 $(.21) $ .14 $ .12 $1.25
Note 18
Subsequent Events
Because of the charge-offs discussed in Notes 1 and 13 above, on
March 12, 1999, Connecticut Valley was notified by the Bank that it would
exercise appropriate remedies in connection with the violation of financial
covenants associated with the $3.75 million loan agreement with the Bank
unless the violation is cured by April 11, 1999. The Company is presently
negotiating with the Bank to purchase Connecticut Valley's outstanding long-
term note.
As a result of the December 3, 1998 Court of Appeals' decision discussed
in Note 13 above, on March 22, 1999, the NHPUC issued an Order which directed
Connecticut Valley to file within five business days its calculation of the
difference between the total FAC and the PPCA revenues that it would have
collected had the 1997 FAC and PPCA rate levels been in effect the entire
year. In its Order, the NHPUC also directed Connecticut Valley to calculate a
rate reduction to be applied to all billings for the period April 1, 1999
through December 31, 1999 to refund the 1998 over collection relative to the
1997 rate level. The Company estimates this amount to be approximately $2.7
million on a pre-tax basis. Connecticut Valley filed the required tariff page
with the NHPUC, under protest and with reservation of all rights, on March 26,
1999.
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 information required by this item with respect to the Company's
directors is incorporated herein by this reference to "Election of Directors"
in the Proxy Statement for the 1999 Annual Meeting of Stockholders. The
Executive Officers information is listed under Part I, Item 1. Definitive
proxy materials will be filed with the Securities and Exchange Commission
pursuant to Regulation 14A on March 31, 1999.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934 requires the
Company's directors and executive officers to file reports of ownership and
changes in ownership of Company securities with the Securities and Exchange
Commission (SEC) and to furnish the Company with copies of all such reports.
It also requires directors, officers and persons who beneficially own more
than ten percent (10%) of the Company's stock to file initial reports of
ownership and subsequent reports of changes in ownership with the SEC and the
New York Stock Exchange. In making this statement, the Company has relied on
copies of reports that have been filed with the SEC.
Based solely on a review of the copies of such reports prepared and filed
with the SEC during 1998 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 except for Mr. Young, who inadvertently
neglected to report the ownership of shares of the Company's Common Stock held
by his spouse. Mr. Young disclaims any voting or investment power over the
shares held by his spouse. The Company does not have a ten percent holder.
Item 11. Executive Compensation.
The information required by this item concerning executive compensation
and directors' compensation is set forth in the sections entitled "Executive
Compensation and Other Transactions", Directors' Compensation", "Report of the
Compensation Committee on Executive Compensation" and "Five-Year Shareholder
Return Comparison Performance Graph" in the Proxy Statement of the Company for
the 1999 Annual Meeting of Stockholders, which are being incorporated herein
by reference. Definitive proxy materials will be filed with the Securities
and Exchange Commission pursuant to Regulation 14A on March 31, 1999.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The information required by this item concerning security ownership is set
forth in the section entitled "Stock Ownership of Directors, Nominees,
Executive Officers and Certain Beneficial Owners" in the Proxy Statement for
the 1999 Annual Meeting of Stockholders, which is being incorporated herein by
reference. Definitive proxy materials will be filed with the Securities and
Exchange Commission pursuant to Regulation 14A on March 31, 1999.
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, 1998
Consolidated Statement of Cash Flows,
for each of the three years ended
December 31, 1998
Consolidated Balance Sheet at December 31,
1998 and 1997
Consolidated Statement of Capitalization
at December 31, 1998 and 1997
Consolidated Statement of Changes in
Common Stock Equity for each of the
three years ended December 31, 1998
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, 1998
Schedules not included have been omitted because they
are not applicable or the required information is shown
in the financial statements or notes thereto. Separate
financial statements of the Registrant (which is primarily
an operating company) have been omitted since they are
consolidated only with those of totally held subsidiaries.
Separate financial statements of subsidiary companies not
consolidated have been omitted since, if considered in
the aggregate, they would not constitute a significant
subsidiary. Separate financial statements of 50% or less
owned persons for which the investment is accounted for
by the equity method by the Registrant have been omitted
since, if considered in the aggregate, they would not
constitute a significant investment.
(a)3. Exhibits (* denotes filed herewith)
Each document described below is incorporated by reference
to the appropriate exhibit numbers and the Commission file
numbers indicated in parentheses, unless the reference to
the document is marked as follows:
* - Filed herewith.
Copies of any of the exhibits filed with the Securities and
Exchange Commission in connection with this document may be
obtained from the Company upon written request.
Exhibit 3 Articles of Incorporation and By-Laws
3-1 By-Laws, as amended June 2, 1997. (Exhibit 3-1, Form 10-Q
June 30, 1997, File No. 1-8222)
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. (Exhibit B-4,
File No. 2-2364)
4-3 Supplemental Indenture dated as of November 15, 1943. (Exhibit B-3,
File No. 2-5250)
4-4 Supplemental Indenture dated as of December 1, 1943. (Exhibit No.
B-4, File No. 2-5250)
4-5 Directors' resolutions adopted December 14, 1943, establishing the
Series C Bonds and dealing with other related matters. (Exhibit
B-5, File No. 2-5250)
4-6 Supplemental Indenture dated as of April 1, 1944. (Exhibit No.
B-6, File No. 2-5466)
4-7 Supplemental Indenture dated as of February 1, 1945. (Exhibit
7.6, File No. 2-5615) (22-385)
4-8 Directors' resolutions adopted April 9, 1945, establishing
the Series D Bonds and dealing with other matters. (Exhibit 7.8,
File No. 2-5615 (22-385)
4-9 Supplemental Indenture dated as of September 2, 1947. (Exhibit
7.9, File No. 2-7489)
4-10 Supplemental Indenture dated as of July 15, 1948, and directors'
resolutions establishing the Series E Bonds and dealing with other
matters. (Exhibit 7.10, File No. 2-8388)
4-11 Supplemental Indenture dated as of May 1, 1950, and directors'
resolutions establishing the Series F Bonds and dealing with other
matters. (Exhibit 7.11, File No. 2-8388)
4-12 Supplemental Indenture dated August 1, 1951, and directors'
resolutions, establishing the Series G Bonds and dealing with other
matters. (Exhibit 7.12, File No. 2-9073)
4-13 Supplemental Indenture dated May 1, 1952, and directors'
resolutions, establishing the Series H Bonds and dealing with other
matters. (Exhibit 4.3.13, File No. 2-9613)
4-14 Supplemental Indenture dated as of July 10, 1953. (July, 1953 Form
8-K, File No. 1-8222)
4-15 Supplemental Indenture dated as of June 1, 1954, and directors'
resolutions establishing the Series K Bonds and dealing with other
matters. (Exhibit 4.2.16, File No. 2-10959)
4-16 Supplemental Indenture dated as of February 1, 1957, and directors'
resolutions establishing the Series L Bonds and dealing with other
matters. (Exhibit 4.2.16, File No. 2-13321)
4-17 Supplemental Indenture dated as of March 15, 1960. (March, 1960
Form 8-K, File No. 1-8222)
4-18 Supplemental Indenture dated as of March 1, 1962. (March, 1962
Form 8-K, File No. 1-8222)
4-19 Supplemental Indenture dated as of March 2, 1964. (March, 1964
Form 8-K, File No, 1-8222)
4-20 Supplemental Indenture dated as of March 1, 1965, and directors'
resolutions establishing the Series M Bonds and dealing with other
matters. (April, 1965 Form 8-K, File No. 1-8222)
4-21 Supplemental Indenture dated as of December 1, 1966, and directors'
resolutions establishing the Series N Bonds and dealing with other
matters. (January, 1967 Form 8-K, File No. 1-8222)
4-22 Supplemental Indenture dated as of December 1, 1967, and directors'
resolutions establishing the Series O Bonds and dealing with other
matters. (December, 1967 Form 8-K, File No. 1-8222)
4-23 Supplemental Indenture dated as of July 1, 1969, and directors'
resolutions establishing the Series P Bonds and dealing with other
matters. (Exhibit B.23, July, 1969 Form 8-K, File No. 1-8222)
4-24 Supplemental Indenture dated as of December 1, 1969, and directors'
resolutions establishing the Series Q Bonds January, and dealing
with other matters. (Exhibit B.24, January, 1970 Form 8-K, File No.
1-8222)
4-25 Supplemental Indenture dated as of May 15, 1971, and directors'
resolutions establishing the Series R Bonds and dealing with other
matters. (Exhibit B.25, May, 1971, Form 8-K, File No. 1-8222)
4-26 Supplemental Indenture dated as of April 15, 1973, and directors'
resolutions establishing the Series S Bonds and dealing with other
matters. (Exhibit B.26, May, 1973, Form 8-K, File No. 1-8222)
4-27 Supplemental Indenture dated as of April 1, 1975, and directors'
resolutions establishing the Series T Bonds and dealing with other
matters. (Exhibit B.27, April, 1975, Form 8-K, File No. 1-8222)
4-28 Supplemental Indenture dated as of April 1, 1977. (Exhibit 2.42,
File No. 2-58621)
4-29 Supplemental Indenture dated as of July 29, 1977, and directors'
resolutions establishing the Series U, V, W, and X Bonds and
dealing with other matters. (Exhibit 2.43, File No. 2-58621)
4-30 Thirtieth Supplemental Indenture dated as of September 15, 1978,
and directors' resolutions establishing the Series Y Bonds and
dealing with other matters. (Exhibit B-30, 1980 Form 10-K, File
No. 1-8222)
4-31 Thirty-first Supplemental Indenture dated as of September 1, 1979,
and directors' resolutions establishing the Series Z Bonds and
dealing with other matters. (Exhibit B-31, 1980 Form 10-K, File
No. 1-8222)
4-32 Thirty-second Supplemental Indenture dated as of June 1, 1981, and
directors' resolutions establishing the Series AA Bonds and dealing
with other matters. (Exhibit B-32, 1981 Form 10-K, File No. 1-8222)
4-45 Thirty-third Supplemental Indenture dated as of August 15, 1983,
and directors' resolutions establishing the Series BB Bonds and
dealing with other matters. (Exhibit B-45, 1983 Form 10-K, File No.
1-8222)
4-46 Bond Purchase Agreement between Merrill, Lynch, Pierce, Fenner &
Smith, Inc., Underwriters and The Industrial Development Authority
of the State of New Hampshire, issuer and Central Vermont Public
Service Corporation. (Exhibit B-46, 1984 Form 10-K, File No.
1-8222)
4-47 Thirty-Fourth Supplemental Indenture dated as of January 15, 1985,
and directors' resolutions establishing the Series CC Bonds and
Series DD Bonds and matters connected therewith. (Exhibit B-47,
1985 Form 10-K, File No. 1-8222)
4-48 Bond Purchase Agreement among Connecticut Development Authority and
Central Vermont Public Service Corporation with E. F. Hutton &
Company Inc. dated December 11, 1985. (Exhibit B-48, 1985 Form
10-K, File No. 1-8222)
4-49 Stock-Purchase Agreement between Vermont Electric Power
Company, Inc. and the Company dated August 11, 1986 relative
to purchase of Class C Preferred Stock. (Exhibit B-49, 1986
Form 10-K, File No. 1-8222)
4-50 Thirty-Fifth Supplemental Indenture dated as of December 15, 1989
and directors' resolutions establishing the Series EE, Series FF
and Series GG Bonds and matters connected therewith. (Exhibit 4-50,
1989 Form 10-K, File No. 1-8222)
4-51 Thirty-Sixth Supplemental Indenture dated as of December 10, 1990
and directors' resolutions establishing the Series HH Bonds and
matters connected therewith. (Exhibit 4-51, 1990 Form 10-K, File
No. 1-8222)
4-52 Thirty-Seventh Supplemental Indenture dated December 10, 1991 and
directors' resolutions establishing the Series JJ Bonds and matters
connected therewith. (Exhibit 4-52, 1991 Form 10-K, File No.
1-8222)
4-53 Thirty-Eight Supplemental Indenture dated December 10, 1993
establishing Series KK, LL, MM, NN, OO. (Exhibit 4-53, 1993 Form
10-K, File No. 1-8222)
4-54 Thirty-Ninth Supplemental Indenture Dated December 29, 1997.
(Exhibit 4-54, 1997 Form 10-K, File No. 1-8222)
4-55 Fortieth Supplemental Indenture Dated January 28, 1998.
(Exhibit 4-55, 1997 Form 10-K, File No. 1-8222)
4-56 Credit Agreement Dated As of November 5, 1977 among
Central Vermont Public Service Corporation, The Lenders
Named Herein and Toronto-Dominion (Texas), Inc., as Agent.
(Exhibit 10.83, 1997 Form 10-K, File No. 1-8222)
4-56.1 First Amendment to Credit Agreement Dated as of
April 15, 1998 (Exhibit 10.83.1, Form 10-Q,
June 30, 1998, File No. 1-8222)
4-56.2 Second Amendment to Credit Agreement Dated as of
June 2, 1998 (Exhibit 10.83.2, 1997 Form 10-Q,
June 30, 1998, File No. 1-8222)
* 4-56.3 Third Amendment to Credit Agreement Dated as of
October 5, 1998
* 4-56.4 Open-End Mortgage, Security Agreement, Assignment of
Rents and Leases, Fixture Filing, and Financing Statement
Dated as of October 5, 1998 between the Company, as
Mortgagor, in Favor of Toronto Dominion (Texas), Inc. as
Collateral Agent for the Secured Parties
* 4-56.5 Security Agreement, dated as of October 5, 1998, between
the Company and Toronto Dominion (Texas), Inc.
Exhibit 10 Material Contracts (*Denotes filed herewith)
Incorporated herein by reference:
10.l Copy of firm power Contract dated August 29, 1958, and
supplements thereto dated September 19, 1958, October 7, 1958,
and October 1, 1960, between the Company and the State
of Vermont (the "State"). (Exhibit C-1, File No. 2-17184)
10.1.1 Agreement setting out Supplemental NEPOOL Understandings
dated as of April 2, 1973. (Exhibit C-22, File No.
5-50198)
10.2 Copy of Transmission Contract dated June 13, 1957, between Velco
and the State, relating to transmission of power. (Exhibit
10.2, 1993 Form 10-K, File No. 1-8222)
10.2.1 Copy of letter agreement dated August 4, 1961, between
Velco and the State. (Exhibit C-3, File No. 2-26485)
10.2.2 Amendment dated September 23, 1969. (Exhibit C-4, File
No. 2-38161)
10.2.3 Amendment dated March 12, 1980. (Exhibit C-92, 1982
Form 10-K, File No. 1-8222)
10.2.4 Amendment dated September 24, 1980. (Exhibit C-93, 1982
Form 10-K, File No. 1-8222)
10.3 Copy of subtransmission contract dated August 29, 1958, between
Velco and the Company (there are seven similar contracts between
Velco and other utilities). (Exhibit 10.3, 1993 Form 10-K,
Form No. 1-8222)
10.3.1 Copies of Amendments dated September 7, 196l, November 2,
1967, March 22, 1968, and October 29, 1968. (Exhibit
C-6, File No. 2-32917)
10.3.2 Amendment dated December 1, 1972. (Exhibit 10.3.2, 1993
Form 10-K, File No. 1-8222)
10.4 Copy of Three-Party Agreement dated September 25, 1957, between
the Company, Green Mountain and Velco. (Exhibit C-7, File No.
2-17184)
10.4.1 Superseding Three Party Power Agreement dated January 1,
1990. (Exhibit 10-201, 1990 Form 10-K, File No. 1-8222)
10.4.2 Agreement Amending Superseding Three Party Power
Agreement dated May 1, 1991. (Exhibit 10.4.2, 1991 Form
10-K, File No. 1-8222)
10.5 Copy of firm power Contract dated December 29, 1961, between the
Company and the State, relating to purchase of Niagara Project
power. (Exhibit C-8, File No. 2-26485)
10.5.1 Amendment effective as of January 1, 1980. (Exhibit
10.5.1, 1993 Form 10-K, File No. 1-8222)
10.6 Copy of agreement dated July 16, 1966, and letter supplement
dated July 16, 1966, between Velco and Public Service Company of
New Hampshire relating to purchase of single unit power from
Merrimack II. (Exhibit C-9, File No. 2-26485)
10.6.1 Copy of Letter Agreement dated July 10, 1968, modifying
Exhibit A. (Exhibit C-10, File No. 2-32917)
10.7 Copy of Capital Funds Agreement between the Company and Vermont
Yankee dated as of February 1, 1968. (Exhibit C-11, File No.
70-4611)
10.7.1 Copy of Amendment dated March 12, 1968. (Exhibit C-12,
File No. 70-4611)
10.7.2 Copy of Amendment dated September 1, 1993. (Exhibit
10.7.2, 1994 Form 10-K, File No. 1-8222)
10.8 Copy of Power Contract between the Company and Vermont Yankee
dated as of February 1, 1968. (Exhibit C-13, File No. 70-4591)
10.8.1 Amendment dated April 15, 1983. (10.8.1, 1993 Form
10-K, File No. 1-8222)
10.8.2 Copy of Additional Power Contract dated February 1,
1984. (Exhibit C-123, 1984 Form 10-K, File No. 1-8222)
10.8.3 Amendment No. 3 to Vermont Yankee Power Contract,
dated April 24, 1985. (Exhibit 10-144, 1986 Form 10-K,
File No. 1-8222)
10.8.4 Amendment No. 4 to Vermont Yankee Power Contract,
dated June 1, 1985. (Exhibit 10-145, 1986 Form 10-K,
File No. 1-8222)
10.8.5 Amendment No. 5 dated May 6, 1988. (Exhibit 10-179,
1988 Form 10-K, File No. 1-8222)
10.8.6 Amendment No. 6 dated May 6, 1988. (Exhibit 10-180,
1988 Form 10-K, File No. 1-8222)
10.8.7 Amendment No. 7 dated June 15, 1989. (Exhibit 10-195,
1989 Form 10-K, File No. 1-8222)
10.9 Copy of Capital Funds Agreement between the Company and Maine
Yankee dated as of May 20, 1968. (Exhibit C-14, File No.
70-4658)
10.9.1 Amendment No. 1 dated August 1, 1985. (Exhibit C-125,
1984 Form 10-K, File No. 1-8222)
10.10 Copy of Power Contract between the Company and Maine Yankee
dated as of May 20, 1968. (Exhibit C-15, File No. 70-4658)
10.10.1 Amendment No. 1 dated March 1, 1984. (Exhibit C-112,
1984 Form 10-K, File No. 1-8222)
10.10.2 Amendment No. 2 effective January 1, 1984. (Exhibit
C-113, 1984 Form 10-K, File No. 1-8222)
10.10.3 Amendment No. 3 dated October 1, 1984. (Exhibit
C-114, 1984 Form 10-K, File No. 1-8222)
10.10.4 Additional Power Contract dated February 1, 1984.
(Exhibit C-126, 1985 Form 10-K, File No. 1-8222)
10.11 Copy of Agreement dated January 17, 1968, between Velco and
Public Service Company of New Hampshire relating to purchase of
additional unit power from Merrimack II. (Exhibit C-16, File
No. 2-32917)
10.12 Copy of Agreement dated February 10, 1968 between the Company
and Velco relating to purchase by Company of Merrimack II unit
power. (There are 25 similar agreements between Velco and
other utilities.) (Exhibit C-17, File No. 2-32917)
10.13 Copy of Three-Party Power Agreement dated as of November 21,
1969, among the Company, Velco, and Green Mountain relating
to purchase and sale of power from Vermont Yankee Nuclear
Power Corporation. (Exhibit C-18, File No. 2-38161)
10.13.1 Amendment dated June 1, 1981. (Exhibit 10.13.1, 1993
Form 10-K, File No. 1-8222)
10.14 Copy of Three-Party Transmission Agreement dated as of
November 21, 1969, among the Company, Velco, and Green Mountain
providing for transmission of power from Vermont Yankee Nuclear
Power Corporation. (Exhibit C-19, File No. 2-38161)
10.14.1 Amendment dated June 1, 1981. (Exhibit 10.14.1, 1993
Form 10-K, File No. 1-8222)
10.15 Copy of Stockholders Agreement dated September 25, 1957,
between the Company, Velco, Green Mountain and Citizens
Utilities Company. (Exhibit No. C-20, File No. 70-3558)
10.16 New England Power Pool Agreement dated as of September 1, 1971,
as amended to November 1, 1975. (Exhibit C-21, File No.
2-55385)
10.16.1 Amendment dated December 31, 1976. (Exhibit 10.16.1
1993 Form 10-K, File No. 1-8222)
10.16.2 Amendment dated January 23, 1977. (Exhibit 10.16.2,
1993 Form 10-K, File No. 1-8222)
10.16.3 Amendment dated July 1, 1977. (Exhibit 10.16.3, 1993
Form 10-K, File No. 1-8222)
10.16.4 Amendment dated August 1, 1977. (Exhibit 10.16.4,
1993 Form 10-K, File No. 1-8222)
10.16.5 Amendment dated August 15, 1978. (Exhibit 10.16.5,
1993 Form 10-K, File No. 1-8222)
10.16.6 Amendment dated January 31, 1979. (Exhibit 10.16.6,
1993 Form 10-K, File No. 1-8222)
10.16.7 Amendment dated February 1, 1980. (Exhibit 10.16.7,
1993 Form 10-K, File No. 1-8222)
10.16.8 Amendment dated December 31, 1976. (Exhibit 10.16.8,
1993 Form 10-K, File No. 1-8222)
10.16.9 Amendment dated January 31, 1977. (Exhibit 10.16.9,
1993 Form 10-K, File No. 1-8222)
10.16.10 Amendment dated July 1, 1977. (Exhibit 10.16.10, 1993
Form 10-K, File No. 1-8222)
10.16.11 Amendment dated August 1, 1977. (Exhibit 10.16.11,
1993 Form 10-K, File No. 1-8222)
10.16.12 Amendment dated August 15, 1978. (Exhibit 10.16.12,
1993 Form 10-K, File No. 1-8222)
10.16.13 Amendment dated January 31, 1980. (Exhibit 10.16.13,
1993 Form 10-K, File No. 1-8222)
10.16.14 Amendment dated February 1, 1980. (Exhibit 10.16.14,
1993 Form 10-K, File No. 1-8222)
10.16.15 Amendment dated September 1, 1981. (Exhibit 10.16.15,
1993 Form 10-K, File No. 1-8222)
10.16.16 Amendment dated December 1, 1981. (Exhibit 10.16.16,
1993 Form 10-K, File No. 1-8222)
10.16.17 Amendment dated June 15, 1983. (Exhibit 10.16.17,
1993 Form 10-K, File No. 1-8222)
10.16.18 Amendment dated September 1, 1985. (Exhibit 10-160,
1986 Form 10-K, File No. 1-8222)
10.16.19 Amendment dated April 30, 1987. (Exhibit 10-172, 1987
Form 10-K, File No. 1-8222)
10.16.20 Amendment dated March 1, 1988. (Exhibit 10-178, 1988
Form 10-K, File No. 1-8222)
10.16.21 Amendment dated March 15, 1989. (Exhibit 10-194, 1989
Form 10-K, File No. 1-8222)
10.16.22 Amendment dated October 1, 1990. (Exhibit 10-203,
1990 Form 10-K, File No. 1-8222)
10.16.23 Amendment dated September 15, 1992. (Exhibit
10.16.23, 1992 Form 10-K, File No. 1-8222)
10.16.24 Amendment dated May 1, 1993. (Exhibit 10.16.24, 1993
Form 10-K, File No. 1-8222)
10.16.25 Amendment dated June 1, 1993. (Exhibit 10.16.25, 1993
Form 10-K, File No. 1-8222)
10.16.26 Amendment dated June 1, 1994. (Exhibit 10.16.26, 1994
Form 10-K, File No. 1-8222)
10.16.27 Thirty-Second Amendment dated September 1, 1995.
(Exhibit 10.16.27, Form 10-Q dated September 30, 1995,
File No. 1-8222 and Exhibit 10.16.27, 1995 Form 10-K,
File No. 1-8222)
10.17 Agreement dated October 13, 1972, for Joint Ownership,
Construction and Operation of Pilgrim Unit No. 2 among Boston
Edison Company and other utilities, including the Company.
(Exhibit C-23, File No. 2-45990)
10.17.1 Amendments dated September 20, 1973, and September 15,
1974. (Exhibit C-24, File No. 2-51999)
10.17.2 Amendment dated December 1, 1974. (Exhibit C-25, File
No. 2-54449)
10.17.3 Amendment dated February 15, 1975. (Exhibit C-26,
File No. 2-53819)
10.17.4 Amendment dated April 30, 1975. (Exhibit C-27, File
No. 2-53819)
10.17.5 Amendment dated as of June 30, 1975. (Exhibit C-28,
File No. 2-54449)
10.17.6 Instrument of Transfer dated as of October 1, 1974,
assigning partial interest from the Company to Green
Mountain Power Corporation. (Exhibit C-29, File No.
2-52177)
10.17.7 Instrument of Transfer dated as of January 17, 1975,
assigning a partial interest from the Company to the
Burlington Electric Department. (Exhibit C-30, File
No. 2-55458)
10.17.8 Addendum dated as of October 1, 1974 by which Green
Mountain Power Corporation became a party thereto.
(Exhibit C-31, File No. 2-52177)
10.17.9 Addendum dated as of January 17, 1975 by which the
Burlington Electric Department became a party thereto.
(Exhibit C-32, File No. 2-55450)
10.17.10 Amendment 23 dated as of 1975. (Exhibit C-50, 1975
Form 10-K, File No. 1-8222)
10.18 Agreement for Sharing Costs Associated with Pilgrim Unit No.2
Transmission dated October 13, 1972, among Boston Edison
Company and other utilities including the Company. (Exhibit
C-33, File No. 2-45990)
10.18.1 Addendum dated as of October 1, 1974, by which Green
Mountain Power Corporation became a party thereto.
(Exhibit C-34, File No. 2-52177)
10.18.2 Addendum dated as of January 17, 1975, by which
Burlington Electric Department became a party thereto.
(Exhibit C-35, File No. 2-55458)
10.19 Agreement dated as of May 1, 1973, for Joint Ownership,
Construction and Operation of New Hampshire Nuclear Units among
Public Service Company of New Hampshire and other utilities,
including Velco. (Exhibit C-36, File No. 2-48966)
10.19.1 Amendments dated May 24, 1974, June 21, 1974,
September 25, 1974, October 25, 1974, and January 31,
1975. (Exhibit C-37, File No. 2-53674)
10.19.2 Instrument of Transfer dated September 27, 1974,
assigning partial interest from Velco to the Company.
(Exhibit C-38, File No. 2-52177)
10.19.3 Amendments dated May 24, 1974, June 21, 1974, and
September 25, 1974. (Exhibit C-81, File No. 2-51999)
10.19.4 Amendments dated October 25, 1974 and January 31,
1975. (Exhibit C-82, File No. 2-54646)
10.19.5 Sixth Amendment dated as of April 18, 1979. (Exhibit
C-83, File No. 2-64294)
10.19.6 Seventh Amendment dated as of April 18, 1979.
(Exhibit C-84, File No. 2-64294)
10.19.7 Eighth Amendment dated as of April 25, 1979. (Exhibit
C-85, File No. 2-64815)
10.19.8 Ninth Amendment dated as of June 8, 1979. (Exhibit
C-86, File No. 2-64815)
10.19.9 Tenth Amendment dated as of October 10, 1979.
(Exhibit C-87, File No. 2-66334 )
10.19.10 Eleventh Amendment dated as of December 15, 1979.
(Exhibit C-88, File No.2-66492)
10.19.11 Twelfth Amendment dated as of June 16, 1980.
(Exhibit C-89, File No. 2-68168)
10.19.12 Thirteenth Amendment dated as of December 31, 1980.
(Exhibit C-90, File No. 2-70579)
10.19.13 Fourteenth Amendment dated as of June 1, 1982.(Exhibit
C-104, 1982 Form 10-K, File No. 1-8222)
10.19.14 Fifteenth Amendment dated April 27, 1984. (Exhibit
10-134, 1986 Form 10-K, File No. 1-8222)
10.19.15 Sixteenth Amendment dated June 15, 1984. (Exhibit
10-135, 1986 Form 10-K, File No. 1-8222)
10.19.16 Seventeenth Amendment dated March 8, 1985. (Exhibit
10-136, 1986 Form 10-K, File No. 1-8222)
10.19.17 Eighteenth Amendment dated March 14, 1986. (Exhibit
10-137, 1986 Form 10-K, File No. 1-8222)
10.19.18 Nineteenth Amendment dated May 1, 1986. (Exhibit
10-138, 1986 Form 10-K, File No. 1-8222)
10.19.19 Twentieth Amendment dated September 19, 1986.
(Exhibit 10-139, 1986 Form 10-K, File No. 1-8222)
10.19.20 Amendment No. 22 dated January 13, 1989. (Exhibit
10-193, 1989 Form 10-K, File No. 1-8222)
10.20 Transmission Support Agreement dated as of May 1, 1973, among
Public Service Company of New Hampshire and other utilities,
including Velco, with respect to New Hampshire Nuclear Units.
(Exhibit C-39, File No. 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. (Exhibit
10.56.3, 1994 Form 10-K, File No. 1-8222)
10.56.4 Amendment No. 4 dated December 31, 1996. (Exhibit
10.56.4, 1996 Form 10-K, file No. 1-8222)
10.57 Highgate Transmission Agreement dated August 1, 1984 by and
between the owners of the project and the Vermont electric
distribution companies. (Exhibit 10-156, 1986 Form 10-K, File
No. 1-8222)
10.57.1 Amendment No. 1 dated September 22, 1985. (Exhibit
10-157, 1986 Form 10-K, File No. 1-8222)
10.58 Vermont Support Agency Agreement re: Quebec Interconnection -
Phase II between Vermont Electric Power Company, Inc. and
participating Vermont electric utilities dated June 1, 1985.
(Exhibit 10-158, 1986 Form 10K, File No. 1-8222)
10.58.1 Amendment No. 1 dated June 20, 1986. (Exhibit 10-159,
1986 Form 10-K, File No. 1-8222)
10.59 Indemnity Agreement B-39 dated May 9, 1969 with amendments 1-16
dated April 17, 1970 thru April 16, 1985 between licensees of
Millstone Unit No. 3 and the Nuclear Regulatory Commission.
(Exhibit 10-161, 1986 Form 10-K, File No. 1-8222)
10.59.1 Amendment No. 17 dated November 25, 1985. (Exhibit
10-162, 1986 Form 10-K, File No. 1-8222)
10.62 Contract for the Sale of 50MW of firm power between
Hydro-Quebec and Vermont Joint Owners of Highgate Facilities
dated February 23, 1987. (Exhibit 10-173, 1987 Form 10-K,
File No. 1-8222)
10.63 Interconnection Agreement between Hydro-Quebec and Vermont
Joint Owners of Highgate facilities dated February 23, 1987.
(Exhibit 10-174, 1987 Form 10-K, File No. 1-8222)
10.63.1 Amendment dated September 1, 1993 (Exhibit 10.63.1,
1993 Form 10-K, File No. 1-8222)
10.64 Firm Power and Energy Contract by and between Hydro-Quebec and
Vermont Joint Owners of Highgate for 500MW dated December 4,
1987. (Exhibit 10-175, 1987 Form 10-K, File No. 1-8222)
10.64.1 Amendment No. 1 dated August 31, 1988. (Exhibit
10-191, 1988 Form 10-K, File No. 1-8222)
10.64.2 Amendment No. 2 dated September 19, 1990. (Exhibit
10-202, 1990 Form 10-K, File No. 1-8222)
10.64.3 Firm Power & Energy Contract dated January 21, 1993
by and between Hydro-Quebec and Central Vermont
Public Service Corporation for the sale back of 25 MW
of power. (Exhibit 10.64.3, 1992 Form 10-K, File No.
1-8222)
10.64.4 Firm Power & Energy Contract dated January 21, 1993
by and between Hydro-Quebec and Central Vermont Public
Service Corporation for the sale back of 50 MW of
power. (Exhibit 10.64.4, 1992 Form 10-K, File No.
1-8222)
10.66 Hydro-Quebec Participation Agreement dated April 1, 1988 for
600 MW between Hydro-Quebec and Vermont Joint Owners of
Highgate. (Exhibit 10-177, 1988 Form 10-K, File No. 1-8222)
10.66.1 Hydro-Quebec Participation Agreement dated April 1,
1988 as amended and restated by Amendment No. 5
thereto dated October 21, 1993, among Vermont
utilities participating in the purchase of electricity
under the Firm Power and Energy Contract by and
between Hydro-Quebec and Vermont Joint Owners of
Highgate. (Exhibit 10.66.1, 1997 Form 10-Q,
March 31, 1997, 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)
10.75.6 Agreement Amendment No. 5 dated November 29, 1993
(Exhibit 10.75.6, 1997 Form 10-K, File No. 1-8222)
10.75.7 Agreement Amendment No. 6 dated November 29, 1994
(Exhibit 10.75.7, 1997 Form 10-K, File No. 1-8222)
10.75.8 Agreement Amendment No. 7 dated November 29, 1995
(Exhibit 10.75.8, 1997 Form 10-K, File No. 1-8222)
10.75.9 Agreement Amendment No. 8 dated February 5, 1997
(Exhibit 10.75.9, 1997 Form 10-K, File No. 1-8222)
10.75.10 Agreement Amendment No. 9 dated February 2, 1998
(Exhibit 10.75.10, 1997 Form 10-K, File No. 1-8222)
10.83 Credit Agreement Dated As of November 5, 1997, see exhibit 4-56;
10.83.1 and 10.83.2, see exhibit 4-56.1 and 4-56.2.
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
A 10.68 Stock Option Plan for Non-Employee Directors dated July 18,
1988. (Exhibit 10-184, 1988 Form 10-K, File No. 1-8222)
A 10.69 Stock Option Plan for Key Employees dated July 18, 1988.
(Exhibit 10-185, 1988 Form 10-K, File No. 1-8222)
A 10.70 Officers Supplemental Insurance Plan authorized July 9, 1984.
(Exhibit 10-186, 1988 Form 10-K, File No. 1-8222)
A 10.71 Officers Supplemental Deferred Compensation Plan dated
November 4, 1985. (Exhibit 10-187, 1988 Form 10-K, File
No. 1-8222)
A 10.71.1 Amendment dated October 2, 1995. (Exhibit 10.71.1,
1995 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 10.72.1 Amendment dated October 2, 1995. (Exhibit 10.72.1,
1995 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 10.73.2 Revised Management Incentive Plan dated May 2, 1995.
(Exhibit 10.73.2, 1995 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 10.79.1 Amendment dated October 2, 1995. (Exhibit No.
10.79.1, 1995 Form 10-K, File No. 1-8222)
A 10.80 Directors' Supplemental Deferred Compensation Plan dated
January 1, 1990 (Exhibit 10.80, 1993 Form 10-K, File No. 1-8222)
A 10.80.1 Amendment dated October 2, 1995. (Exhibit No.
10.80.1, 1995 Form 10-K, File No. 1-8222)
A 10.81 Officers' Supplemental Deferred Compensation Plan dated
January 1, 1990 (Exhibit 10.81, 1993 Form 10-K, File No. 1-8222)
A 10.82 Management Incentive Plan for Executive Officers dated January 1,
1997. (Exhibit 10.82, 1996 Form 10-K, File No. 1-8222)
A 10.83 Management Incentive Plan for Executive Officers dated
January 1, 1998 (Exhibit A10.83, Form 10-Q, March 31, 1998,
File No. 1-8222)
*A 10.84 Officers' Change of Control Agreement dated January 1, 1998
*A 10.85 Officers' Supplemental Retirement and Deferred Compensation Plan
as Amended and Restated Effective January 1, 1998
A 10.86 1993 Stock Option Plan for Non-employee Directors (Exhibit 28 to
Registration Statement, Registration 33-62100)
A 10.87 1997 Stock Option Plan for Key Employees (Exhibit 4.3 to
Registration Statement, Registration 333-57001)
A 10.88 1997 Restricted Stock Plan for Non-employee Directors and Key
Employees (Exhibit 4.3 to Registration Statement, Registration
333-57005)
A - Compensation related plan, contract, or arrangement.
21. Subsidiaries of the Registrant
* 21.1 List of Subsidiaries of Registrant
23. Consents of Experts and Counsel
* 23.1 Consent of Independent Public Accountants
27. Financial Data Schedule (filed electronically only)
(b) Reports on Form 8-K:
The Company filed the following reports on Form 8-K during
the quarter ended December 31, 1998:
1. Item 5. Other Events, dated October 27, 1998 re:
(a) Vermont Retail Rate Settlement
(b) Change in Board of Directors
(c) Revolving Credit and Competitive Advance Facility
2. Item 5. Other Events, dated December 3, 1998 re:
(a) Report of the Working Group on Vermont's
Electricity Future
(b) Vermont Retail Rate Increase
(c) Fuel Adjustment Clause and Purchased Power Cost Adjustment
(FAC/PPCA) for Connecticut Valley
Electric Company Inc.
(d) First Circuit Decision
(e) Other - Carl E. Horton, Sr. choosing not to be
a candidate for directorship
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 25, 1999 (except with respect to
the matter discussed in Note 18, as to which the date is March 26, 1999). Our
audit was made for the purpose of forming an opinion on the basic financial
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 states, 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
March 26, 1999
Schedule II
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 1998
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:
$ 77,925(1)
354,950(2)
__________
Reserve for uncollectible
accounts receivable $1,945,893 $1,126,136 $ 432,875 $1,263,108(3) $2,241,796
========== ========== ========== ========== ==========
Accumulated depreciation of
miscellaneous properties:
Rental water heater program $3,629,089 $ 360,158 - $ 271,172(4) $3,718,075
Other 24,918(5)
365,134 242,677 - 9,985(6) 572,908
__________ __________ _________ _________ __________
$3,994,223 $ 602,835 $ 306,075 $4,290,983
========== ========== ========= ========= ==========
Reserves shown separately:
Injuries and damages reserve $ 225,580 - - - $ 225,580
========== ==========
Environmental Reserve $4,367,151 $ 500,000 $5,532,871(7) $ 452,918(8) $9,947,104
========== ========== ========== ========== ==========
Accumulated provision for
rate refunds - $2,737,345 - - $2,737,345
========== ==========
(1) Amount due from collection agency.
(2) Collections of accounts previously written off.
(3) Uncollectible accounts written off.
(4) Retirement/Sale of rental water heaters.
(5) Write down of computers.
(6) Retirement of equipment.
(7) Additional reserve.
(8) Expenses charged against reserve.
Schedule II
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 1997
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:
$ 91,909(1)
415,992(2)
Reserve for uncollectible 770,496(3)
__________
accounts receivable $1,132,195 $751,530 $1,278,397 $1,216,229(4) $1,945,893
========== ======== ========== ========== ==========
Accumulated depreciation of
miscellaneous properties:
Rental water heater program $3,553,149 $357,961 - $ 282,021(5) $3,629,089
320,811(6)
Other 731,892 106,248 - 152,195(7) 365,134
__________ ________ __________ __________
$4,285,041 $464,209 $ 755,027 $3,994,223
========== ======== ========== ==========
Reserves shown separately:
Injuries and damages reserve $ 225,580 - - - $ 225,580
========== ==========
Environmental Reserve $5,176,725 - - $ 809,574(8) $4,367,151
========== ========== ==========
(1) Amount due from collection agency.
(2) Collections of accounts previously written off.
(3) Transferred from miscellaneous receivables.
(4) Uncollectible accounts written off.
(5) Retirement/Sale of rental water heaters.
(6) Sale of non-utility Property.
(7) Amortization of Customer Information Systems.
(8) Expenses charged against reserve.
Schedule II
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 1996
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:
$ 81,367(1)
Reserve for uncollectible 299,244(2)
________
accounts receivable $1,551,606 $670,083 $380,611 $1,470,105(3) $1,132,195
========== ======== ======== ========== ==========
Accumulated depreciation of
miscellaneous properties:
Rental water heater program $3,508,493 $356,274 - $ 311,618(4) $3,553,149
Other 295,765 436,127 - - 731,892
__________ ________ __________ __________
$3,804,258 $792,401 $ 311,618 $4,285,041
========== ======== ========== ==========
Reserves shown separately:
Injuries and damages reserve $ 225,580 - - - $ 225,580
========== ==========
Environmental Reserve $5,464,059 - - $ 287,334(5) $5,176,725
========== ========== ==========
(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) Expenses charged against reserve.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
CENTRAL VERMONT PUBLIC SERVICE
CORPORATION
By /s/ Robert H. Young
__________________________________________
Robert H. Young, President and
Chief Executive Officer
March 29, 1999
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
DATE NAME AND TITLE
March 29, 1999 /s/ Robert H. Young
__________________________________________
Robert H. Young
President and Chief Executive Officer
and Director
March 29, 1999 /s/ Francis J. Boyle
__________________________________________
Francis J. Boyle, Senior Vice President,
Chief Financial Officer and Treasurer
(Principal Financial Officer)
March 29, 1999 /s/ James M. Pennington
__________________________________________
James M. Pennington, Vice President,
Controller (Principal Accounting Officer)
March 29, 1999 /s/ Frederic H. Bertrand
__________________________________________
Frederic H. Bertrand
Chairman of the Board and Director
March 29, 1999 /s/ Robert L. Barnett
__________________________________________
Robert L. Barnett
Director
March 29, 1999 /s/ Rhonda L. Brooks
__________________________________________
Rhonda L. Brooks
Director
March 29, 1999 /s/ Robert G. Clarke
__________________________________________
Robert G. Clarke
Director
March 29, 1999 /s/ Luther F. Hackett
__________________________________________
Luther F. Hackett
Director
March 29, 1999 /s/ Patrick J. Martin
__________________________________________
Patrick J. Martin
Director
March 29, 1999 /s/ Mary Alice McKenzie
__________________________________________
Mary Alice McKenzie
Director
March 29, 1999 /s/ Janice L. Scites
__________________________________________
Janice L. Scites
Director