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 141,499 customers in nearly three-quarters of the towns, villages and cities in Vermont. 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 69% of total mWh sales excluding mWh sales related to the Virginia Power Alliance (611,225 mWh) for 2000. 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 18% of total mWh sales for 2000.
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 10,435 customers in 13 communities in New Hampshire. 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 2000. Sales to its five largest retail customers during the same period aggregated about 18% of Connecticut Valley's total electric revenues for 2000.
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 also 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.
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In addition, the Company has a wholly owned non-utility subsidiary, Catamount Resources Corporation, which was formed for the purpose of holding the Company's subsidiaries that invest in unregulated business opportunities.
For additional information on 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 ("NHPUC") 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 Unit #3 ("Unit #3") an 1159 mW nuclear generating facility, respectively.
Connecticut Valley is subject to the regulatory authority of the 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 eight 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
The Company is subject to environmental regulations in the licensing and operation of the generation, transmission, and distribution facilities in which it has an 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 may impact the Company's generation, transmission, distribution, transportation
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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 refer to Part II, Item 8 Note 14, 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, and 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 Part II Item 8 herein for disclosures relating to the shut down of the Maine Yankee, Connecticut Yankee and Yankee Atomic Nuclear Power plants.
Competition
Competition currently 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 ("DPS") 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 DPS if they are satisfied that the benefits outweigh any potential risk to the State. However, the DPS may proceed to file the retail proposal with the PSB either upon approval by the review board or the failure of the PSB to act within sixty (60) days of the submission. Section 212(c) provides that the DPS 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.
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Section 212(d) provides that upon PSB approval of a DPS 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 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 PSB after a hearing. If either party is dissatisfied, the statute allows them to appeal the PSB'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.
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.
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
1997 Retail Rate Case: 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 (Docket No. 6018). Action on this case is stayed pending an interlocutory appeal to the Vermont Supreme Court.
1998 Retail Rate Case: 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 ("VJO") contract with Hydro-Quebec. In this proceeding the PSB delayed the
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examination of the prudence and used-and-usefulness of the Hydro-Quebec Contract pending the VSC's decision in the appeal of Docket No. 6018. After extensive negotiation, on October 28, 1998 the DPS filed a Memorandum of Understanding between the DPS 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 ("GMP") in its February 1998 rate order. To reflect both the final and the temporary cost of service determinations, the Memorandum of Understanding proposed a "temporary rate increase" of 4.6% 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 Memorandum of Understanding in its entirety.
On February 9, 2001, the Vermont Supreme Court issued a decision on the Company's 1998 rate case appeal that reversed the PSB's decision on the preclusion issues and remanded the case to the PSB for further proceedings consistent with the Vermont Supreme Court's decision. However, if the PSB subsequently issues a final rate order adopting the disallowance methodology used to determine the temporary Hydro-Quebec disallowance described above for the duration of the VJO Power Contract, the Company would not be able to recover approximately $179.7 million of power costs over the life of the contract, including $11.3 million in 2001 and $11.4 million in 2002, $11.5 million in 2003, $11.7 million in 2004 and $11.8 million in 2005. In such an event, the Company would be required to take an immediate charge to earnings of approximately $179.7 million (pre-tax). Such an outcome could jeopardize the Company's ability to continue as a going concern. However, at this time, the Company does not believe that such a loss is probable particularly in view of the January 2001 PSB Order issued in GMP's proceedings, and the decision of the Vermont Supreme Court reversing and remanding the PSB's order.
Deseasonalized Rates: On April 13, 2000, the Company and the DPS filed a stipulated agreement with the PSB to end winter-summer rate differentials for the Company's Vermont customers. On June 8, 2000, the PSB approved the Company's request to end the winter-summer rate differential and, therefore, the Company will now have flat rates throughout a given year. Winter rates were reduced by 14.9%, while summer rates were increased 10.5%. The rate design change will be revenue neutral over a 12-month period. The additional 2000 revenues, resulting from implementing this change in mid-year, have been applied to reduce or eliminate certain regulatory deferrals, as directed by the PSB.
2000 Retail Rate Case: In an effort to mitigate projected eroding earnings and cash flow prospects in the near future, due mainly to under recovery of its Hydro-Quebec power costs, on November 9, 2000, the Company filed with the PSB a request for a 7.6% rate increase ($19.0 million of annualized revenues) to be effective July 1, 2001. In the request the Company also asked for the PSB to find that the Company's share of the VJO Power Contract be found to be "prudent" and "used and useful".
The PSB suspended the rate filing and a schedule has been set to review the rate case. An order from the PSB is expected before July 24, 2001.
For additional information regarding rate increase requests see PART II, Item 7 - Rates and Regulation and Item 8 - Retail Rates herein.
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New Hampshire Retail Rates
Connecticut Valley's retail rate tariffs, approved by the NHPUC, contain a Fuel Adjustment Clause ("FAC") and a Purchased Power Cost Adjustment ("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 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 under collections, the 1998 under collections 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 under collections from prior periods mentioned above. 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.
Effective June 1, 1999, pursuant to an appeals court order related to the temporary restraining order issued by the federal district court, the NHPUC reduced Connecticut Valley's FAC and PPCA rates to the level in effect at December 31, 1997. Such level caused a $600,000 under collection of power costs for the subsequent seven-month period.
On the basis of estimates of costs for 2000 and reconciliations from 1999, the combined 2000 FAC and PPCA rates would have resulted in an increase in revenues of approximately $1.9 million for 2000. The increase was caused by the reduction of FAC and PPCA rates to the level in effect at December 31, 1997. In fact, had the NHPUC not ordered the reduction in rates to a level below cost of service effective June 1, 1999, Connecticut Valley would have filed for a 4.8% decrease. The NHPUC ordered the FAC and PPCA to remain unchanged at the level in effect at December 31, 1997.
On March 6, 2000, the federal district court granted summary judgement to Connecticut Valley and the Company on their claim under the filed-rate doctrine and issued a permanent injunction mandating that the NHPUC allow Connecticut Valley to pass through to its retail customers its wholesale costs incurred under the RS-2 rate schedule with the Company. The federal district court also ruled that Connecticut Valley was entitled to recover those wholesale costs that the NHPUC has disallowed in retail rates since January 1, 1997. The NHPUC appealed the decision to the appeals court and also requested the appeals court to stay the federal district court's order pending review on appeal. In response, Connecticut Valley offered to place the additional revenues in escrow pending the outcome of appeal. The appeals court denied the NHPUC's request for a stay so long as the incremental revenues were placed in escrow.
Pursuant to the March 6, 2000 federal district court's order, on March 17, 2000 Connecticut Valley filed a rate request with the NHPUC for an Interim FAC/PPCA to recover the balance of wholesale costs not recovered since January 1997. To mitigate the rate increase percentage, the Interim FAC/PPCA were designed to recover current power costs and a substantial
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portion of past under collections by the end of 2000; the remainder of the past under collections will be collected during 2001 along with 2001 power costs. The NHPUC held a hearing on April 7, 2000 to review the 12.3% increase that would raise $1.6 million of revenues in 2000, and issued an order approving the rates as temporary effective May 1, 2000.
On July 25, 2000, the Appeals Court affirmed the federal district court's March 6, 2000 order granting summary judgement to Connecticut Valley and the Company. The NHPUC then asked the appeals court to reconsider its decision; however, that request was denied. As a result, Connecticut Valley recorded a $2.0 million after-tax gain in the third quarter of 2000. On November 27, 2000, the NHPUC filed a petition for writ of certiorari with the United States Supreme Court. On February 20, 2001 the United States Supreme Court denied the petition for certiorari, thus leaving the Court of Appeals approval of the permanent injunction intact. See PART II, Item 7 herein for additional information regarding New Hampshire FERC Proceedings and Item 8 Note 13 herein for information regarding New Hampshire Retail Rate/Federal Court Proceedings.
On the basis of estimates of costs for 2001 and reconciliations from 2000, the combined 2001 FAC and PPCA rates should result in an increase in revenues of approximately $0.8 million for 2001. The increase is primarily caused by 1) higher power costs in 2001, 2) under-collections of 2000 power costs and the portion of previous under-collections from 1997 due to lower than forecast sales in 2000, and 3) lower forecast sales in 2001.
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 Conservation and Load Management ("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. The NHPUC had approved the termination of C&LM activities by Connecticut Valley at the end of 1998. The NHPUC issued an order allowing an adequate level of recovery of lost revenues and administration C&LM costs for 2000.
Connecticut Valley filed to eliminate seasonal rates and to implement non-seasonal rates because the wholesale power market rules had been revised in New England such that the disproportionate cost emphasis placed on a utility's annual peak had been eliminated. Higher winter rates during the time the Company would likely have experienced its annual peak had signaled this cost emphasis to retail customers. Pursuant to a stipulation signed by the NHPUC staff, the Office of the Consumer Advocate, and Claremont, the NHPUC allowed non-seasonal rates effective January 1, 2000.
Connecticut Valley also purchases power from several Independent Power Producers ("IPP's"), who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. In 2000, under long-term contracts with these qualifying facilities, Connecticut Valley purchased 39,998 mWh, of which 37,603 mWh were purchased from Wheelabrator Claremont Company, L.P., ("Wheelabrator") who owns a solid waste plant. Connecticut Valley filed a complaint with FERC stating its concern that Wheelabrator has not been a qualifying facility since the plant began. The FERC denied the complaint and subsequent request for rehearing, and as such, the Company appealed to the D.C. Circuit Court of Appeals. The D.C. Circuit Court of Appeals denied the Company's appeal but indicated the Company could seek relief from the NHPUC. As such, on May 12, 2000, the Company filed a petition with the NHPUC seeking
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(1) to amend the contract to permit purchase of net rather than gross output of the plant and (2) a refund, with interest, of past purchases of the difference between net and gross output. The Company cannot predict the outcome of this matter. See PART II, Item 8 herein for additional information regarding the Wheelabrator Power Contract.
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 decrease of $63,000 or 0.5% for 2000 power costs, (2) a reconciliation of 1999 revenues to actual costs which resulted in a refund of $683,000, including interest, and (3) a revenue increase of $139,000 or 1.2% for 2001 power costs.
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 sought to be recovered through an exit fee, expressed on a net present value basis as of December 31, 2000, is approximately $41.5 million. The exit fee 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's 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 re-filed with FERC. 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.
Based on the FERC's acceptance of the filing, the Company filed a request for an exit fee mechanism to collect stranded costs resulting from the cancellation of the contract with Connecticut Valley. The request described all of the ways Connecticut Valley will become an unbundled transmission customer of the Company subsequent to termination, and established 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.
During April and May 1999, hearings were held at the FERC before the Administrative Law Judge. The ruling of the Administrative Law Judge could be issued at any time. Thereafter, the FERC will act on the Judge's recommendations. See PART II, Item 7 herein for additional information regarding New Hampshire FERC Proceedings and Item 8 Note 13 herein for information regarding New Hampshire Retail Rate/Federal Court Proceedings.
On July 9,1996, the Company filed a comprehensive, open access transmission tariff ("Tariff No. 7" or "Tariff") with the FERC in compliance with Order 888 to replace the previous Tariff No. 6. 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 VELCO. The Tariff would provide transmission service that is comparable to that
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provided to native load customers. Charges for such service would be based upon the Company's cost of service for transmission. The Tariff has been revised to include separate charges for the Highgate and Phase I/II HVDC facilities. 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 rate making 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 and to update certain fixed charges and methodologies. All FERC orders received have approved such modifications.
In 1997 the Company gave notice of termination effective December 31, 1999 to the seven customers taking transmission service under its Transmission Tariff No. 3. The seven customers began taking service under the Transmission Tariff No. 7 beginning January 1, 2000.
The Company is currently working with other transmission providers in New England to develop a Regional Transmission Organization in compliance with FERC Order 2000.
See PART II, Item 7 herein for additional information regarding Regional Transmission Organizations.
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 2,558,875 mWh for the year ended December 31, 2000. The maximum one-hour integrated demand during that period was 430 mW, which occurred on December 28, 2000. The Company's and Connecticut Valley's total energy generation and purchased power in 2000, including that related to all resale customers, was 4,047,330 mWh.
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The following tabulation shows the sources of such energy and capacity available to the Company and Connecticut Valley for the year ended December 31, 2000. For additional information related to purchased power costs, refer to PART II, Item 7, herein.
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 unit with a combined nameplate capability of 28.9 mW.
Jointly Owned Plants
The Company has joint-ownership interests in the following generating and transmission plants:
Name
Location
Fuel
Type
Ownership
mW
Entitlement
Net
Generation
mWh
Load
Factor
Net Plant
Investment
Millstone Unit #3
Waterford,
Connecticut
Nuclear
1.73%
20.0
174,903
99.6%
$48,233,396
Wyman #4
Yarmouth,
Maine
Oil
1.78%
11.0
24,007
24.8%
$ 1,194,219
Joseph C. McNeil
Burlington,
Vermont
Various
20.00%
10.6
61,430
66.0%
$ 6,863,338
Highgate
Transmission
Facility
Highgate Springs, Vermont
47.35%
N/A
N/A
N/A
$ 8,107,230
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The Company receives its share of the output and capacity of Millstone Unit #3, a 1159 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 Converter, a 225 mW facility is directly connected to the Hydro-Quebec System to the north of the Converter and to the VELCO System for delivery of power to Vermont Utilities. This facility can deliver power in 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 21, 2012.
Vermont Yankee's net capability is 522 mW of which about 162.6 mW (See Note 1) is the Company's net entitlement. Vermont Yankee's plant performance for the past five years is shown below:
Availability
Factor
(See Note 2)
Capacity
Factor
(See Note 3)
84.5
82.8
95.4
93.3
75.2
73.5
90.9
88.8
99.5
99.2
Vermont Yankee was shut down for scheduled refueling outages in 1995, 1996, 1998 and 1999.
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 Capability
Company's
Entitlement
Maine Yankee
See Notes (4)
See Notes (4)
Connecticut Yankee
See Notes (4)
See Notes (4)
Yankee Atomic
See Notes (4)
See Notes (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
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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, including the potential sale of Vermont Yankee, refer to PART II, Item 8 herein.
Notes:
Currently, the Company resells at cost, through VELCO, about 20 mW of its original
entitlement to other Vermont utilities.
"Availability Factor" means the hours that the plant is capable of producing electricity
divided by the total hours in the period.
"Capacity Factor" means the total net electrical generation divided by the product of the
maximum design electrical rating capacity of 514 mW through April 30, 1995 and 522 effective
May 1, 1995, multiplied by the total hours in the period.
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 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 include charges for decommissioning costs in the cost of capacity, as approved by the FERC.
The Company's obligations for decommissioning costs for Vermont Yankee, Maine Yankee, Connecticut Yankee and Yankee Atomic are as follows (dollars in millions):
Date of
Study
Total
Estimated
Obligation
CVPS
Obligation
Nuclear generating companies:
Vermont Yankee
$312.7
$ 109.4
Maine Yankee
$536.0
$ 10.7
Connecticut Yankee
$588.0
$ 11.8
Yankee Atomic
$461.0
$ 16.1
Vermont Yankee's current decommissioning cost study is based on a 1994 site study, stated in 1993 dollars. The FERC approved settlement agreement allowed $312.7 million, as the estimated decommissioning cost. Based on the study's assumed cost escalation rate of 5.4% per annum and an expiration of Vermont Yankee's operating license in the year 2012, the estimated current cost of decommissioning is $451.8 million and, at the end of 2012, is approximately $815.2 million. The current value of the pro rata portion of decommissioning costs recorded to date is $321.4 million of which the Company's share is $112.5 million.
Under the FERC approved settlement agreement, Vermont Yankee was required to file with FERC an updated decommissioning cost study by April 1, 1999. On May 13, 1999, in light of the ongoing discussions involving the possible sale of the Vermont Yankee nuclear power plant, the FERC approved a settlement agreement deferring the required filing date. A sale of the plant, if pursued, would likely result in the transfer of responsibility for decommissioning the plant to the new owner and make a revised schedule of decommissioning collections unnecessary.
On November 17, 1999, Vermont Yankee executed an Asset Purchase Agreement (Original Agreement) with AmerGen Energy Co. ("AmerGen"), which is
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owned by PECO Energy Company and British Energy. The Original Agreement was submitted to the PSB for approval and a PSB decision was expected in mid to late October. At the June 2000 hearings before the PSB, the DPS had opposed approval of the sale. At the request of the petitioners and the DPS, the PSB issued an order giving AmerGen, Vermont Yankee and its sponsors, including the Company, and the DPS until November 15, 2000 to file a settlement agreement; if none was filed, the PSB stated it would issue its decision in this docket shortly thereafter. On November 15, 2000, a letter was filed with the PSB indicating a settlement had been reached, and on November 16, 2000, a Memorandum of Understanding including a revised Asset Purchase Agreement and Power Purchase Agreement (PPA) was filed with the PSB. On November 17, 2000, the PSB issued an order including, for guidance of the parties, the PSB's conclusions, which would have been issued in October, and which, if issued, would have resulted in denial of approval of the Original Agreement. The order also affirmed a status conference scheduled for November 22, 2000 to consider a schedule for review of the settlement, events which have occurred since the close of evidence, and penalties, if any, resulting from the one-day late filing of the settlement.
The settlement responded to various issues raised by the DPS during this proceeding. The settlement included an increased purchase price ranging from $23.6 million to $40 million depending on when the sale would occur; a reduced amount of $37 million that Vermont Yankee would pay into the decommissioning funds at closing, lower fixed rates per megawatt hour for energy to be purchased through 2012 under the Power Purchase Agreement (PPA), an obligation on AmerGen's part to pay for the Spring 2001 refueling outage, including the fuel to be installed in the reactor, an obligation on AmerGen's part to reimburse Vermont Yankee for credit insurance premiums or to pay for credit insurance directly, and an obligation by AmerGen to pay for the fuel already in the reactor through a reduction in prices under the PPA. In addition to the value considerations above, the PPA had a low market adjuster (LMA) to address concerns that market prices may be lower than the stated PPA rates. This LMA provided for reductions in the PPA pricing when wholesale prices drop below the PPA price by a stated percentage. In return, AmerGen would assume full responsibility for all future operating costs and the estimated $815.2 million cost for decommissioning the plant at the end of its operating license in 2012.
On December 8, 2000 the PSB issued a decision to allow Entergy (a second potential purchaser) to intervene in the Vermont Yankee/AmerGen sale docket. Additionally, Dominion Resources and Constellation Energy Group (third and fourth potential purchasers) have expressed to the PSB an interest in purchasing the Vermont Yankee plant. At a hearing on December 21, 2000 the PSB rejected intervenors' motion to dismiss the AmerGen sale, and instructed the owners of Vermont Yankee to file their response to Entergy's bid by January 17, 2001.
On January 12, 2001, Entergy filed its offer plus a confidential offer in the event Vermont Yankee could negotiate exclusively with Entergy. On January 17, 2001, Vermont Yankee, GMP and the Company filed their responses. In its response, the Company stated that two bids by Entergy, plus the indications of interest in the Vermont Yankee plant by Dominion Resources and Constellation Energy, and other nuclear sales provide further support for the company's conclusion that the revised AmerGen transaction no longer represents the best market value option when compared to the likely (but not guaranteed) outcome of a timely auction. On January 26, 2001, the PSB held a status conference to discuss what actions the PSB should take in response to the Entergy offers.
On February 14, 2001, the PSB issued its Order Dismissing Petition in Docket No. 6300, the proceeding in which the Company, along with GMP, Vermont
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Yankee and AmerGen sought Board approval of the sale of the Vermont Yankee nuclear power plant to AmerGen. In this Order, the PSB determined that the proposed purchase price, as filed in November 2000 pursuant to a Memorandum of Understanding, did not reflect the fair market value of the plant and, therefore, the sale did not promote the general good of the State of Vermont. Subject to certain procedural matters, the PSB will dismiss the petition for approval. This ruling is consistent with the Company's position. The Company will now participate with Vermont Yankee management to determine whether an auction best serves the interests of the Company; other possible outcomes include continuing to own and operate the plant, selling the plant to Entergy in accordance with their proposals, or prematurely retiring the plant from service. This process is expected to take place over the next several months with the goal of reaching a conclusion by the end of calendar 2001 if possible.
During 1996, Vermont Yankee initiated a Design Basis Documentation project expected to be complete by December 31, 2001. This project was undertaken to incorporate all design documentation into a centralized system. The objective is to ensure that Vermont Yankee maintains its safety margins in connection with any plant modifications. The Design Basis Documentation project will create a set of design basis documents, which will support more efficient systematic problem solving, maintenance, and system overview. This effort supports the safe, cost effective, long-term operation of the Vermont Yankee nuclear power plant. Vermont Yankee received FERC approval in 1996 to defer these unrecovered study costs and amortize the costs through billings to Sponsors over the remaining license life of the Plant. The Company's 35% share of the total cost for this Project is expected to be $7.6 million. See Part II Items 7 and 8 for additional information.
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 and 2) a 1.7303% joint-ownership interest in Unit #3 of Millstone Nuclear Power Station.
The Company is responsible for paying its ownership percentage of decommissioning costs for Millstone Unit #3. Based on a 1997 study, the total estimated obligation at December 31, 2000 was approximately $580.9 million and the total funded obligation was about $247.5 million. The Company's share for the total obligation and funded obligation was approximately $10.7 and $4.2 million, respectively. These costs are included in depreciation expenses.
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.
On August 7, 1997, the Company and the other non-operating owners of Millstone Unit #3 filed a demand for arbitration with Connecticut Light and Power Company and Western Massachusetts Electric Company, both NU affiliates, and lawsuits against NU and its trustees. The arbitration and lawsuits sought to recover costs associated with replacement power, operation and maintenance costs and other costs resulting from the shutdown of Millstone Unit #3 in 1996. The non-operating owners claimed 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. A settlement of these allegations was reached on July 27, 2000. The cash
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settlement of $5,445,000 was received in August 2000 and is reflected as other income in the Consolidated Statement of Income.
On September 15, 1999, NU announced its intent to auction its nuclear generating plants, including Millstone Unit #3. On August 7, 2000, the Connecticut Department of Public Utility Control announced that Dominion Resources, Inc. was the successful bidder in the auction. The sale is expected to become final in April 2001. Pursuant to the terms of the August 4, 2000 settlement with NU, the Company participated as a potential seller in that auction. Upon notification of the sales price, the Company declined the purchase offer.
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. Negotiations of new contracts or renegotiation of existing contracts routinely occurs, often focusing on one of the four components at a time. The cost of the 1999 reload was approximately $21.0 million, and the cost of the 2001 reload is estimated to be approximately $16.0 million. Future refueling costs will depend on market and contract prices.
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. These delays by the DOE have caused Vermont Yankee to consider other costly alternatives for storing high level waste.
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 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 2000, Vermont Yankee accumulated $109.2 million in an irrevocable trust to be used exclusively for defeasing this obligation ($115.4 million including accrued interest) at some future date, provided the DOE complies with the terms of the aforementioned contract.
Vermont Yankee has primary responsibility 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 2008 refueling outage. Vermont Yankee is also investigating other options for additional storage capacity beyond the year 2008.
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Various legal proceedings have been filed by the owners and operators of nuclear power plants, and by states and state regulatory agencies against DOE and the federal government to enforce the DOE's obligation to dispose of spent nuclear fuel and seeking damages resulting from DOE's breach of those obligations. In addition, legislation has been introduced in Congress in the past several years to assure that DOE carries out its obligations and to protect the funds paid to the government by utilities and their customers that were intended to pay for the disposal of utilities spent nuclear fuel.
In July, 1996 the U.S. Court of Appeals for the District of Columbia Circuit ruled that DOE had an unconditional obligation to begin disposing of the utilities' spent nuclear fuel by January 31, 1998, and that the absence of an interim storage facility did not excuse DOE from that obligation. In November 1997, the same court in ruling on a petition brought by 36 utilities, including Vermont Yankee, reaffirmed the 1996 ruling but declined to order DOE to accept spent nuclear fuel, saying that the utilities had another potentially adequate remedy under the DOE contract.
After the January 1998 deadline passed without compliance by DOE with its contractual and statutory obligation, 41 utilities, including Vermont Yankee, and 60 states and state regulatory commissions, petitioned the same Court to compel DOE to act. In orders issued in May 1998 and July 1998, the Court declined to order DOE to act and again directed the utilities to pursue relief in accordance with their DOE contracts. In November 1998, the U.S. Supreme Court denied petitions by the Government and by the states and state agencies to review the lower Court's decisions.
Beginning in February 1998, a series of lawsuits have been filed with the U.S. Court of Federal Claims seeking damages from the Government for DOE's breach of its obligation to begin disposing of the utilities' spent fuel by the 1998 deadline. In October and November 1998, the Court granted a summary judgement in favor of Yankee Atomic Electric Company, Connecticut Yankee Power Company and Maine Yankee Atomic Power Company as to DOE's liability for its breach of the 1998 obligation. The Court rejected the Government's argument that the utilities must first bring claims for damages to the DOE Contracting Officer.
On August 31, 2000, the U.S. Court of Appeals for the Federal Circuit decided appeals from both Yankee and Northern States cases, ruling that the utilities were entitled to sue in the U.S. Court of Federal Claims for breach of contract damages and need not first submit equitable adjustment claims to the DOE contracting Officer.
In a series of filings to the Chief Judge of the U.S. Court of Federal Claims and the ten judges who have been assigned the fourteen spent fuel damages cases brought in that Court, the Government on January 8, 2001 moved to have all the cases reassigned to a single judge. The Government stated that, once the cases were reassigned, it expected to seek consolidation of all the cases in order to determine in a consolidated proceeding an annual spent fuel acceptance and priority schedule binding on all Standard Contract holders. Once all cases are so reassigned the Government suggested that it might seek to bind those utilities that have not yet initiated spent fuel damages cases to the outcome for the consolidated proceeding.
The average energy and capacity costs to the Company of energy generated at the Vermont Yankee plant was 4.78, 4.06, 5.81, 5.14 and 3.92 cents per kWh for the years 1996 through 2000, respectively.
The Company had 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
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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 $9.5 billion. Beyond that a licensee is indemnified under the Price-Anderson Act, 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 $9.3 billion per incident by assessing $88.1 million against each of the 106 reactor units that are currently subject to the Program in the United States, limited to a maximum assessment of $10.0 million per incident per nuclear unit in any one year. The maximum assessment is adjusted at least every five years to reflect inflationary changes. Currently 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 capacity and associated energy from Hydro-Quebec. 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 is purchasing varying amounts of power from Hydro-Quebec under the Vermont Joint Owners ("VJO") contract through 2016. 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 from January 1, 2001 through October 31, 2016 is 131 mW. The total commitment to purchase power under these contracts on a nominal basis is approximately $937 million net of power sellbacks over the contract term, as of December 31, 2000. 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 makes 54 mW of Phase I/II capacity available to HQ for its use to deliver an existing Firm Energy Contract or jointly marketed energy contracts to buyers in NEPOOL, during the period from 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 received 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, upon four year's written notice, to reduce capacity deliveries by up to 50 mW beginning as early as 2004 until 2015. This option includes the use of a like amount of the Company's Phase I/II facility rights. Hydro-Quebec also can exercise an option, upon one year's written notice, to curtail energy deliveries from an annual load factor of 75% to 50% due to adverse hydraulic conditions in Quebec. This can be exercised five times between November 2000 and October 2015.
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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, 1999 the Company's VJO obligation is approximately 43% or $937 million 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 $2.2 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 a 61-day interruption of a significant portion of scheduled contractual energy 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. On the basis of that examination, the VJO determined that Hydro-Quebec has been and remains unable to make available capacity with the degree of firmness required by the VJO Power Contract. That determination has prompted the VJO to initiate an arbitration proceeding. In the arbitration, the VJO is seeking to terminate the contract, to recover damages associated with Hydro-Quebec's failure to comply with the contract, and to recover capacity payments made during the period of non-delivery.
In September 1999 an initial two weeks of hearings were held dealing primarily with issues of contract interpretation. The second phase of the arbitration hearings has concluded and a final decision in the case in expected in the first half of 2001. In accordance with a PSB Accounting Order, the Company has deferred incremental costs associated with this arbitration of approximately $6.3 million through December 31, 2000. The deferred costs have been offset by the incremental revenue from deseasonalized rates that were implemented July 1, 2000, as directed by the Vermont PSB. As of December 31, 2000 excess revenues of $3.8 million have been applied to these deferred costs. Recovery of these costs will be determined in the pending rate proceedings.
Other Purchases
Cogeneration/Independent Power Qualifying Facilities - A number of independent producers using hydroelectric, biomass, and refuse-burning generation are currently producing energy, which is purchased by the Company. The majority of the energy is purchased by a state appointed purchasing agent who purchases and redistributes the power to all Vermont utilities, for the benefit of customers. For the year ended December 31, 2000, the Company and Connecticut Valley received 200,919 mWh from these sources for which it paid $22,197,575.
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 engaged or proposing to engage in the wholesale or retail electric power business in New England. NEPOOL's function 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"), was 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
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participants will continue as an alternative to the ISO wholesale spot market.
The ISO is governed by the principles put forth in FERC Order 888 under rules defined by NEPOOL and approved by FERC. They include, providing independent, open and fair access to the regional transmission system, establishing a non-discriminatory governance structure, facilitating market-based wholesale electric transactions, and ensuring the efficient management and reliable operation of the regional bulk power system.
The ISO also established a bidding system for the newly defined generation products which forms the basis for the ISO's economic dispatch (based on bid prices) of the generation products. This system provides a settlement mechanism which prices 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 pays, as before, the actual costs for its generation products used to serve its load or taken to market. A participant submits 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 receives the market-clearing price based on the highest bids accepted for the residual product. If a participant needs to purchase generation products from the ISO wholesale market to serve its load, those purchases are made at market clearing prices.
The ISO also provides the main marketplace for participants to secure open access transmission for transactions delivered on the Pool Transmission Facilities ("PTF"). The Company is currently working with other transmission providers in New England to develop a Regional Transmission Organization in compliance with FERC Order 2000. See PART II, Item 7 herein for additional information regarding Regional Transmission Organizations.
The Company's peak demand for 2000 occurred on December 28 and equaled 430 mW. At the time of this peak, the Company had a reserve margin of 28%. NEPOOL's peak for the year occurred on June 27, 2000 and totaled 21,919 mW.
Power Resources - Future
The Company generally has 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 continues to be involved with conservation and load management programs as described below.
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 would 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. VELCO operates pursuant to the terms of the 1985 Four-Party Agreement, as
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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.
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, or 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, or 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 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, and 125,000 shares of Class C preferred stock, of which 60,000 shares and 100,000 shares, respectively, were outstanding at December 31, 2000. In addition, four issues of First Mortgage Bonds, aggregating $40,152,000 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") were authorized and outstanding at December 31, 2000. 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 2001 to transmit power to Vermont utilities. The costs of such facilities are presently estimated at $20,062,510 including allowance for funds used during construction calculated at a rate of approximately 7.5%. For a description of VELCO's properties, see "VELCO" under Item 2.
Item 2. Properties.
The Company The Company's properties are operated as a single system which is interconnected by the transmission lines of VELCO, NEP and PSNH. The Company owns and operates 23 small generating stations with a total current nameplate capability of 70.1 mW. The Company's joint ownership interests include, a 1.78% interest in an oil generating plant in Maine; a 20% interest in a wood, gas and oil-fired generating plant in Vermont; a 1.73% interest in a nuclear generating plant in Connecticut; and a 47.35% interest in a transmission interconnection facility in Vermont.
The electric transmission and distribution systems of the Company include about 615 miles of overhead transmission lines, about 7,414 miles of overhead distribution lines and about 290 miles of underground distribution lines, all of which are located in Vermont except for about 22 miles in New Hampshire and about 2 miles in New York.
Connecticut Valley Connecticut Valley's electric properties consist of two principal systems in New Hampshire which are not interconnected, however, each system is connected directly with facilities of the Company.
The electric systems of Connecticut Valley include about 2 miles of transmission lines, about 435 miles of overhead distribution lines and about 12 miles of underground distribution lines.
All of 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 on either land owned in fee or pursuant to easements, most 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 with the lines of Niagara Mohawk Power Corporation at the Vermont-New York state line near Whitehall, New York, and Bennington, Vermont, and with the submarine cable of NYPA near Plattsburgh, New York; on the south and east with the lines of New England Power Company and PSNH; on the south with
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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 with the transmission line of Hydro-Quebec at the Quebec-Vermont border in the Town of Norton, Vermont; and connecting with the transmission line of New England Electric Transmission Corporation, a subsidiary of National Grid USA, at the Vermont-New Hampshire border near New England Power Company's Moore hydro-electric generating station.
Item 3.
Item 3. Legal Proceedings.
On August 7, 1997, the Company and the other non-operating owners of Millstone Unit #3 filed a demand for arbitration with Connecticut Light and Power Company and Western Massachusetts Electric Company, both Northeast Utilities ("NU") affiliates, and lawsuits against NU and its trustees. The arbitration and lawsuits sought to recover costs associated with replacement power, operation and maintenance costs and other costs resulting from the shutdown of Millstone Unit #3 in 1996. The non-operating owners claimed that NU and two of its wholly owned subsidiaries failed to comply with the 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. A settlement of these allegations was reached on July 27, 2000. The cash settlement of $5,445,000 was received in August 2000 and is reflected as other income in the Consolidated Statement of Income.
On September 15, 1999, NU announced its intent to auction its nuclear generating plants, including Millstone Unit #3. On August 7, 2000, the Connecticut Department of Public Utility Control announced that Dominion Resources, Inc. was the successful bidder in the auction. The sale is expected to become final in April 2001. Pursuant to the terms of the settlement with NU which resolved the Company's claims against NU relating to the extended 1996 outage of Millstone Unit #3, the Company participated as a potential seller in that auction. Upon notification of the sales price, the Company declined the purchase offer.
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.
Item 4. Submission of Matters to a Vote of Security Holders
There were no matters submitted to security holders during the fourth quarter of 2000.
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PART II
Item 5.
Item 5. Market for Registrant's Common
Equity and Related Stockholder Matters.
(a) The Company's common stock is listed on the New York Stock Exchange ("NYSE") under the trading symbol CV. Newspaper listings of stock transactions use the abbreviation CVtPS or CentlVtPS and the Internet trading symbol is CV.
The table below shows the high and low sales price of the Company's common stock, as reported on the NYSE composite tape by The Wall Street Journal, for each quarterly period during the last two years as follows:
(b) As of December 31, 2000, there were 10,663 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 1999 and 2000.
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, 2000, the Common Stock Equity of the unconsolidated Company was 38.4% of total capitalization.
For additional information regarding dividend payment level and dividend restrictions see Item 8 herein.
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Item 6.
Item 6. Selected Financial Data.
(Dollars in thousands, except per share amounts)
For the year
Operating revenues
$333,926
$419,815
$303,835
$304,732
$290,801
Net income before extraordinary
charge
$ 18,043
$ 16,584
$ 3,983
$ 17,151
$ 19,442
Extraordinary charge net of taxes
-
-
-
$ 811
-
Net income
$ 18,043
$ 16,584
$ 3,983
$ 16,340
$ 19,442
Earnings available for common
stock
$ 16,264
$ 14,722
$ 2,038
$ 14,312
$ 17,414
Consolidated return on average
common stock equity
8.6%
7.9%
1.1%
7.5%
9.4%
Earnings per basic and diluted
share of common stock before
extraordinary charge
$1.42
$1.28
$.18
$1.32
$1.51
Earnings per basic and diluted
share of Common stock
$1.42
$1.28
$.18
$1.25
$1.51
Cash dividends paid per share of
common stock
$.88
$.88
$.88
$.88
$.84
Book value per share of common
stock
$16.57
$16.05
$15.63
$16.38
$16.19
Net cash provided by operating
activities
$ 60,867
$ 31,232
$ 21,743
$ 41,974
$ 43,007
Dividends paid
$ 11,888
$ 11,950
$ 12,006
$ 12,630
$ 11,728
Construction and plant
expenditures
$ 14,968
$ 13,231
$ 16,046
$ 13,841
$ 18,952
Conservation and load management
expenditures
$ 1,136
$ 2,440
$ 2,208
$ 1,837
$ 1,589
At End of Year
Long-term debt
$152,975
$155,251
$ 90,077
$ 93,099
$117,374
Capital lease obligations
$ 13,978
$ 15,060
$ 16,141
$ 17,223
$ 18,304
Redeemable preferred stock
$ 16,000
$ 17,000
$ 18,000
$ 19,000
$ 20,000
Total capitalization (excluding
current portion of debt)
$381,704
$379,386
$311,454
$324,499
$350,201
Total assets
$539,838
$563,959
$530,282
$531,940
$502,968
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Item 7.
Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations.
Forward Looking Statements Statements contained in this report that are not historical fact (including Management's Discussion and Analysis of Financial Condition and Results of Operation) are forward looking statements intended to qualify for the safe-harbors from liability established by the Private Securities Reform Act of 1995. Statements made that are not historical facts are forward looking and, accordingly, involve estimates, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward looking statements. Actual results will depend, among other things, upon the actions of regulators, pending rate cases before the Vermont Public Service Board ("PSB"), the outcome of litigation involving the Company's regulated companies, the performance of the Vermont Yankee nuclear power plant ("Vermont Yankee"), weather conditions, and the performance of the Company's unregulated businesses. The Company cannot predict the outcome of any of these matters.
Earnings Overview
Central Vermont Public Service Corporation's (the "Company") 2000 net income was $18.0 million or $1.42 per share of common stock, which equates to an 8.6% return on average common equity. This compares to net income and earnings per share of common stock of $16.6 million and $1.28 in 1999, and $4.0 million and $.18 in 1998. The return on average common equity was 7.9% for 1999 and 1.1% for 1998.
Increased 2000 earnings versus 1999 resulted mainly from nonrecurring gains related to a favorable Millstone Unit #3 settlement and a favorable Connecticut Valley Electric Company ("Connecticut Valley") First Circuit Court of Appeals decision amounting to $3.2 million after-tax, or $.28 per share of common stock and $1.7 million after-tax, or $.14 per share of common stock, respectively, and higher utility revenues of $0.8 million after-tax, or $.06 per share of common stock, principally due to a Federal Energy Regulatory Commission ("FERC") ordered refund of transmission costs from Citizens Utilities. In addition, Connecticut Valley reversals of disallowed power costs previously accrued and expensed in 1999, had a positive impact of $0.6 million after-tax, or $.05 per share of common stock, and lower net losses at SmartEnergy Services had a positive impact of $0.5 million after-tax, or $.05 per share of common stock. Lower operating costs of $1.6 million after-tax, or $.13 per share of common stock, resulted from lower service restoration costs and lower regulatory costs related to retail rates. This was offset by the negative impact of $2.6 million, after-tax, or $.23 per share of common stock, due to higher accruals in 2000 for the expected under recovery of power costs on the Hydro-Quebec power contract compared to 1999. Higher net power costs of $2.4 million after-tax, or $.22 per share of common stock, primarily resulted from accrued installed capability ("ICAP") deficiency charges in ISO-New England due to a FERC Order which is currently on appeal and increased capacity costs related to the Hydro-Quebec power contracts. In addition, lower earnings at Catamount Energy Corporation ("Catamount") amounted to $1.2 million after-tax, or $.12 per share of common stock, mainly related to a write down of a portion of the Gauley River equity investment, higher net losses from Catamount's investment in Thetford and Catamount's share of costs incurred in connection with its investment in a wind farm project in Germany.
For 1999 compared to 1998, improved net income and earnings per share of common stock resulted from higher retail revenues associated with the positive impact of a 4.7% temporary Vermont rate increase ($7.1 million after-tax, or $.61 per share of common stock) as well as a 2.0% increase in
retail mWh sales ($2.6 million after-tax, or $.23 per share of common stock).
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In addition, in 1998 the Company accrued $4.3 million, or $.38 per share of common stock, for disallowed Hydro-Quebec power costs expected in 1999. Net income and earnings per share of common stock for 1999 reflect the positive effect of reversing $4.3 million after-tax, or $.38 per share of common stock, resulting from disallowed Hydro-Quebec purchased power costs in the same amount accrued during the fourth quarter of 1998. This positive effect was offset by the recognition of 2000 disallowed Hydro-Quebec power costs of about $1.7 million after-tax, or $.15 per share of common stock, in the fourth quarter of 1999. Net income and earnings per share of common stock were also affected by non-utility losses of $2.5 million after-tax, or $.22 per share of common stock, related to SmartEnergy Services, Inc.'s ("SmartEnergy") proportionate share in Home Service Solutions LLC (d.b.a. The Home Service Store) ("HSS") and Catamount, and higher operating and maintenance costs of $3.1 million after-tax, or $.28 per share of common stock, caused by two major storms in 1999 as well as increased regulatory and legal costs, partially offset by the favorable effect of PSB Accounting Orders for the deferral of certain legal and regulatory costs of $1.3 million, or $.12 per share of common stock. Higher interest costs of $1.1 million, or $.10 per share of common stock were incurred, due to the sale of Second Mortgage Bonds and increases in average outstanding short-term debt. Lower power costs of $1.7 million after-tax, or $.14 per share of common stock, principally related to better performance at the Millstone Unit #3 nuclear power plant ("Unit #3")(Unit #3 was off-line during the first half of 1998) and the Vermont Yankee plant due to the extended refueling outage in 1998, partially offset by higher power costs related to the Hydro-Quebec contract.
Also, for 1998, net income and earnings per share of common stock for the Company's utility business reflected the net effect at Connecticut Valley of after-tax 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 after-tax 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 Note 13 to the Consolidated Financial Statements.
Other factors affecting results for 2000 are described in the following Results of Operations.
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 operating revenues and mWh sales for 2000, 1999, and 1998 is set forth below:
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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 1999, retail mWh sales for 2000 increased 28,724 mWh, or 1.2% and related revenues decreased $0.7 million, or .3% compared to 1999. The revenue decrease was primarily attributable to the rate reduction for the funding of the State of Vermont sponsored Energy Efficiency Utility ("EEU").
Compared to 1998, retail mWh sales for 1999 increased 46,326 mWh, or 2.0% and related revenues increased $16.7 million, or 6.5%. The revenue increase was primarily attributable to the 4.7% temporary Vermont retail rate increase discussed above and the impact of higher mWh sales.
Effective January 1, 2000 power purchased from Hydro-Quebec was recorded net of entitlement sales to Hydro-Quebec. The 1999 and 1998 Entitlement sales included in Resale sales has been restated for comparison purposes in the table above, along with Purchased Power and Produced Energy (mWh) shown in the table below.
For 2000, entitlement mWh sales increased 53% when compared to 1999. The increase primarily resulted from Vermont Yankee short-term unit swap transactions with other nuclear facilities in New England. Offsetting short-term purchases related to the swap transactions are included in the Purchased Power and Produced Energy (mWh) table below. In addition, 1999 included a Vermont Yankee refueling outage while there was no refueling outage in 2000. A portion of the Company's share of Vermont Yankee's output is sold to other utilities.
For 1999, entitlement mWh sales increased 19.5% compared to 1998. This increase resulted primarily from the Vermont Yankee extended refueling outage in 1998.
Alliance resale sales resulted from activity by the Company through its Alliance with Virginia Power in jointly supplying wholesale power primarily in the Northeast states. In the third quarter of 1999, the Company and Virginia Power agreed to discontinue the Alliance. For 2000, Alliance resale sales decreased 2,375,457 mWh and related revenues decreased $77,924 million compared to 1999. For 1999 Alliance resale sales increased 2,629,282 mWh and related revenues increased $88.9 million compared to 1998.
Other resale sales decreased 296,802 mWh compared to 1999 and increased 218,622 compared to 1998. Related revenues decreased $1.6 million for 2000 and increased $6.5 million for 1999. These variances reflect current market conditions in Vermont and New England. These sales made on a short-term basis include sales to ISO-New England and other utilities in New England.
Compared to 1999, Other revenues increased $4.5 million partly due to a non-recurring gain of $2.6 million for the reversal of the provision for rate refunds due to a favorable First Circuit Court of Appeals decision allowing Connecticut Valley to recover all of its power costs in rates, and a $0.8 million FERC ordered refund of transmission costs from Citizens Utilities.
For 1999 compared to 1998, Other revenues increased $2.4 million primarily due to refund obligations recorded in the fourth quarter of 1998 by Connecticut Valley related to under recovery of power costs.
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The table below summarizes the components of increases or decreases in revenues compared to the prior year (dollars in thousands):
Revenue increase (decrease) from:
Retail mWh sales
$ 2,880
$ 4,516
Retail rates
(3,606)
12,144
Changes in firm resale sales
(18)
Changes in entitlement sales
(77)
1,505
Change in Alliance sales
(77,924)
88,850
Changes in other resale sales
(1,587)
6,526
Changes in other revenues
4,478
2,373
Net increase (decrease) over prior year
$(75,854)
$115,980
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. In 2000, the Company entered into Vermont Yankee short term unit swap transactions with other nuclear facilities in New England. A breakdown of the Company's energy sources, including the unit swap transactions and excluding sources related to the Alliance, is shown below:
The Company maintains a 1.7303% joint-ownership interest in Unit #3, of the Millstone Nuclear Power Station and owns a 2% equity interest in Connecticut Yankee. These two plants are currently 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 unit with a combined nameplate capability of 28.9 mW.
Millstone Unit #3
On August 7, 1997, the Company and the other non-operating owners of Unit #3 filed a demand for arbitration with Connecticut Light and Power Company and Western Massachusetts Electric Company, both NU affiliates, and lawsuits against NU and its trustees. The arbitration and lawsuits sought to recover costs associated with replacement power, operation and maintenance costs and other costs resulting from the shutdown of Unit #3 in 1996. The non-operating owners claimed that NU and two of its wholly owned subsidiaries failed to comply with NRC's regulations, failed to operate the facility in
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accordance with good operating practice and attempted to conceal their activities from the non-operating owners and the NRC. A settlement of these allegations was reached on July 27, 2000. The cash settlement of $5,445,000 was received in August 2000 and is reflected as other income on the Consolidated Statement of Income.
On September 15, 1999, NU announced its intent to auction its nuclear generating plants, including Unit #3. On August 7, 2000, the Connecticut Department of Public Utility Control announced that Dominion Resources, Inc. was the successful bidder in the auction. The sale is expected to become final in April 2001. Pursuant to the terms of the August 4, 2000 settlement with NU, the Company participated as a potential seller in that auction. Upon notification of the sales price, the Company declined the purchase offer.
Based on the most recent decommissioning estimate in 1997, the Company's total share of Unit #3 decommissioning costs at December 31, 2000 was $10.7 million. As of December 31, 2000, the Company has funded $4.2 million of these costs.
Vermont Yankee
The Vermont Yankee nuclear power plant, which provides more than one-third of the Company's power supply, did not experience a scheduled refueling outage in 2000. The next scheduled outage is on April 27, 2001 and is expected to last 35 days. The 1999 refueling outage began on October 29, 1999 and the plant returned to service December 2, 1999. The 1998 refueling outage (March 21-June 3) extended 26 days beyond the scheduled 49 days.
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 Vermont Yankee and Millstone Unit #3. During 2000, the Company deferred $.1 million for maintenance costs.
During 1996, Vermont Yankee initiated a Design Basis Documentation project expected to be complete by December 31, 2001. This project was undertaken to incorporate all design documentation into a centralized system. The objective is to ensure that Vermont Yankee maintains its safety margins in connection with any plant modifications. The Design Basis Documentation project will create a set of design basis documents which will support more efficient systematic problem solving, maintenance, and system overview. This effort supports the safe, cost effective, long term operation of the Vermont Yankee plant. Vermont Yankee received FERC approval in 1996 to defer these unrecovered study costs and amortize the costs through billings to Sponsors over the remaining license life of the Plant. The Company's 35% share of the total cost for this project is expected to be approximately $7.6 million.
On October 15, 1999 the Company and other owners of Vermont Yankee accepted a bid for sale of the plant to AmerGen Energy Co. ("AmerGen"), which is owned by PECO Energy Company and British Energy. On November 17, 1999, Vermont Yankee executed an Asset Purchase Agreement with AmerGen. On November 16, 2000, the owners of Vermont Yankee accepted and submitted to the PSB an improved offer for the sale of the plant to AmerGen. This agreement would have also involved the Company entering into a contract to purchase a portion of the power produced by this plant.
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The revised agreement included an increased price to be paid by AmerGen for the plant and property ranging from $23.6 million to $40 million depending on when the sale would occur; a reduced amount of $37 million that Vermont Yankee must pay into the decommissioning funds at closing, lower fixed rates per megawatt hour for energy to be purchased through 2012 under the Power Purchase Agreement ("PPA"), an obligation on AmerGen's part to pay for the Spring 2001 refueling outage, including the fuel to be installed in the reactor, an obligation on AmerGen's part to reimburse Vermont Yankee for credit insurance premiums or to pay for credit insurance directly, and an obligation by AmerGen to pay for the fuel already in the reactor through a reduction in prices under the PPA. In addition to the value considerations above, the PPA had a low market adjuster ("LMA") to address concerns that market prices may be lower than the stated PPA rates. This LMA provided for reductions in the PPA pricing when wholesale prices drop below the PPA price by a stated percentage. In return, AmerGen would have assumed full responsibility for all future operating costs and the estimated $815.2 million cost for decommissioning the plant at the end of its operating license in 2012.
On December 8, 2000 the PSB issued a decision to allow Entergy (a second potential purchaser) to intervene in the Vermont Yankee/AmerGen sale docket. Additionally, Dominion Resources and Constellation Energy Group (third and fourth potential purchasers) have expressed to the PSB an interest in purchasing the Vermont Yankee plant. At a hearing on December 21, 2000 the PSB rejected intervenors' motion to dismiss the AmerGen sale, and instructed the owners of Vermont Yankee to file their response to Entergy's bid by January 17, 2001.
On January 12, 2001, Entergy filed its offer, plus a confidential offer effective in the event Vermont Yankee could negotiate exclusively with Entergy. On January 17, 2001, Vermont Yankee, Green Mountain Power ("GMP") and the Company filed their responses. In its response, the Company stated that the two bids by Entergy, plus the indications of interest in the Vermont Yankee plant by Dominion Resources and Constellation Energy, and other nuclear plant sales provide further support for the Company's conclusion that the revised AmerGen transaction no longer represents the best market value option when compared to the likely (but not guaranteed) outcome of a timely auction. On January 26, 2001, the PSB held a status conference to discuss what actions the PSB should take in response to the Entergy offers.
On February 14, 2001, the PSB issued its Order Dismissing Petition in Docket No. 6300, the proceeding in which the Company, along with GMP, Vermont Yankee Nuclear and AmerGen sought PSB approval of the sale of the Vermont Yankee nuclear plant to AmerGen. In this Order, the PSB determined that the proposed purchase price, as filed in November 2000, pursuant to a Memorandum of Understanding, did not reflect the fair market value of the plant and, therefore, the sale did not promote the general good of the State of Vermont. Subject to certain procedural matters, the PSB will dismiss the petition for approval. This ruling is consistent with the Company's position. The Company will participate with Vermont Yankee management to determine whether an auction best serves the interests of the Company; other possible outcomes include continuing to own and operate the plant, selling the plant to Entergy in accordance with their proposals, or prematurely retiring the plant from service. This process is expected to take place over the next several months with the goal of reaching a conclusion by the end of 2001 if possible.
Maine Yankee
On August 6, 1997, the Maine Yankee nuclear power plant was prematurely retired from commercial operation. The Company relied on Maine Yankee for
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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 $558.9 million including a decommissioning obligation of $252.5 million, as of December 31, 2000.
On January 19, 1999, Maine Yankee and the active intervenors filed an Offer of Settlement with the FERC which the FERC has approved. As a result, 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 are resolved. Also resolved are the issues raised by the secondary purchasers, who purchased Maine Yankee power through agreements with the original owners, limiting the amounts they will pay for decommissioning the Maine Yankee plant and settling other points of contention affecting individual secondary purchasers.
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.
Connecticut Yankee reached a settlement with the FERC and the intervenors that allows for the cost recovery of the expected decommissioning costs now estimated at $588.0 million in January 2000 dollars, as well as other appropriate costs of service. The settlement rates became effective September 1, 2000 following the FERC order of July 26, 2000. Connecticut Yankee is required to commence a new filing before the FERC no later than July 1, 2004 to review the status of decommissioning expenditures, the expected remaining decommissioning costs and their collections, and other appropriate issues.
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.
As of July 2000, Yankee Atomic has collected from its sponsors sufficient funds based on a current forecast, to complete the decommissioning effort and to recover all other FERC approved costs of service. Therefore, Yankee Atomic has discontinued billings to its sponsors pending the need to increase or decrease the funds available for the completion of its financial obligations including decommissioning. Such a change would require a FERC review and approval.
Maine Yankee, Connecticut Yankee and Yankee Atomic Decommissioning Costs
Currently, 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. As of December 31, 2000, the Company has completed its obligation for decommissioning costs based on current estimates related to Yankee Atomic. The Company's share of remaining costs with respect to Maine Yankee and Connecticut Yankee's decisions to discontinue operation is estimated to be $11.5 million and $5.4 million, respectively, at December 31, 2000. These amounts are subject to ongoing review and revisions and are reflected in the accompanying balance sheet both as regulatory assets and nuclear dismantling liabilities (current and non-current).
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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. This would have the effect of lowering costs to customers. 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 should not have a material adverse effect on the Company's earnings or financial condition.
Cogeneration/Independent Power Qualifying Facilities
A number of Independent Power Producers ("IPPs") using hydroelectric, biomass, and refuse-burning generation are currently producing energy that is allocated to the Company for the benefit of its customers by operation of Vermont law. The majority of the energy is purchased by a state appointed purchasing agent who purchases and redistributes the power to all Vermont utilities, for the benefit of customers, based on their pro-rata share of total Vermont retail kilowatthour sales for the previous calendar year. Under these long-term contracts, in 2000 the Company received 200,919 mWh of which 144,310 mWh is associated with the Vermont Electric Power Producers and 37,603 mWh with the New Hampshire/Vermont Solid Waste Plant owned by Wheelabrator Claremont Company, L.P. The Company expects to purchase approximately 200,000 mWh of independent power output in each year 2001 to 2005. Based on the forecast level of production, the total commitment in the next five years to purchase power from these independent power facilities is estimated to be $118 million.
As part of the Company's initiative to cut power costs and restructure Vermont's utility industry, on August 3, 1999, the Company, GMP, Citizens Utilities and all of Vermont's 15 municipal utilities, filed a petition with the PSB requesting modification of the contracts between the IPPs and the state appointed purchasing agent. The petition is based on unique provisions of the existing contracts and PSB regulations that provide for modifications and alterations that serve the public interest. The petition outlines seven specific elements that, if implemented, would reduce the purchase power costs of these contracts.
On September 3, 1999, the PSB responded to the Company's petition by opening a formal investigation in Docket No. 6270 regarding these contracts. Shortly thereafter, Citizens Utilities, Hardwick Electric Department and the Burlington Electric Department notified the PSB that they were withdrawing from the petition but they will participate in the case as non-moving parties. In a separate action before the Chittenden County Superior Court brought by several IPP owners, GMP's full participation in this PSB proceeding was enjoined. That injunction is now on appeal to the Vermont Supreme Court. The Company, the other moving utilities and the Vermont Department of Public Service ("DPS") have requested that the PSB issue an order requiring GMP's full participation in the PSB proceeding. The PSB declined to rule on the request but retained authority to require GMP to provide specific information or to submit any other specific filing. On November 22, 2000, the IPPs filed dispositive motions in Docket No. 6270 urging the PSB to declare that it lacks jurisdiction to grant relief sought by the Company's Petition. On January 8, 2001, the Company and the other petitioning utilities filed responses to the IPP's motions supporting the Board's exercise of jurisdiction, as called under the Petition. The DPS also made a filing in support of jurisdiction.
The IPPs have also filed a related proceeding in the Washington County
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Superior Court contending that the PSB rules pertaining to IPPs, which the utilities have relied upon, in part, in their petition before the PSB, contains a so-called "scrivener's error." By motion filed in the Superior Court in September, 2000, the IPPs have sought summary judgement in this action. Simultaneously, the PSB has asked the Superior Court to dismiss the IPP's action. On November 17, 2000, the Company and the other Vermont municipal utilities participating in this action filed a response to the IPP's request urging the Superior Court to decline to exercise jurisdiction over the scrivener's error matter since doubt exists as to whether the IPP's have raised a justiciable controversy suitable for resolution by the Superior Court. On January 19, 2001, the Washington County Superior Court dismissed the IPP's action. By notice dated January 22, 2001, the IPP's appealed the Superior Court's dismissal to the Vermont Supreme Court. A decision on the appeal is not expected within calendar year 2001.
At this time, proceedings are continuing in PSB Docket No. 6270. The PSB has not yet established a schedule for final resolution of this matter.
Generating Units
The Company owns and operates 20 hydroelectric generating units, two gas turbines and one diesel peaking unit with a combined nameplate capability of 70.1 mW.
The Company is currently in the process of relicensing or preparing to relicense eight separate hydroelectric projects under the Federal Power Act. These projects, some of which are grouped together under a single license, represent approximately 29.9 mW, or about 66.8% of the Company's total hydroelectric nameplate capacity. In the new licenses, the FERC is expected to impose conditions designed to address the impact of the projects on fish and other environmental concerns. The Company is unable to predict the specific impact of the imposition of such conditions, but capital expenditures and operating costs are expected to increase in the short term to meet these licensing obligations and net generation from these projects will decrease in future periods.
Peterson Dam: The Company has worked with environmental groups and the State of Vermont since 1998 to develop a plan to relicense Peterson Dam, a 6.2 mW hydroelectric station on the Lamoille River. The Vermont Natural Resources Council ("VNRC") has proposed removal of the dam, a 1948 hydro-generating unit that produces power to energize approximately 3,000 homes per year.
In August 2000, talks broke down, and the VNRC called publicly for removal of the dam. The Company has initiated broader discussions with VNRC, Trout Unlimited, the Vermont Agency of Natural Resources and other parties, related to the economic, reliability and environmental issues that Peterson's removal would create. Management cannot predict the outcome of this issue or the costs of replacement power, if any.
Other
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 the NEPOOL hourly clearing market to take advantage of immediate pricing and other market conditions. Revenue from sale transactions is used to reduce purchased power costs. Any purchases are included in Other sources in the Sources of Energy table above. In addition, in 1999 and 1998, the Company also engaged in marketing activities with Virginia Power, which jointly supplied wholesale power primarily in the Northeast states discussed above. In the third quarter of
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1999, the Company discontinued this Alliance and the remaining committed
purchases under the Alliance were fulfilled in 2000. These purchases are excluded from the sources of energy table above.
Net Purchased Power and Production Fuel
The net cost components of purchased power and production fuel costs, including Alliance purchases, for the past three years were as follows (dollars in thousands):
For 2000, purchased capacity costs increased $6.0 million compared to 1999, resulting from the negative impact of net higher loss accruals of $4.6 million in 2000 for expected under recovery of power costs on the Hydro- Quebec power contract, and accrued ICAP deficiency charges in ISO-New England of $2.5 million due to a December 2000 FERC Order, which is currently on appeal. In addition, costs related to the Hydro-Quebec power contract increased by $5.4 million. The increased capacity costs were partially offset by a favorable impact of lower Connecticut Valley loss accruals related to disallowed power costs of $1.2 million, lower Vermont Yankee capacity costs of $2.3 million including the impact of refueling outage deferrals, lower decommissioning costs of $1.0 million which is primarily related to Yankee Atomic, and fewer Alliance related capacity costs of $1.6 million.
For 1999, purchased capacity costs decreased $8.0 million compared to 1998. This decrease was primarily due to the positive impacts of recognizing in 1998 disallowed 1999 Hydro-Quebec power costs of $7.4 million and disallowed 1999 Connecticut Valley power costs of $1.6 million. Partially offsetting this decrease were scheduled cost increases under the Hydro-Quebec contract of $3.0 million and the recognition in 1999 of disallowed first quarter 2000 Hydro-Quebec power costs of $2.9 million, disallowed 2000 Connecticut Valley power costs of $1.2 million, as well as higher costs of $1.7 million, in 1998, for the Vermont Yankee extended outage.
Energy costs are directly related to the variable prices of oil and nuclear fuel but, more importantly, to the proportion of the Company's purchased energy that comes from each of these fuel sources. Energy purchases decreased by $79.4 million, primarily from a $76.7 million decrease in Alliance purchases which are offset by the decrease in alliance resale sales discussed above. Excluding the Alliance, energy purchases decreased
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$2.7 million for 2000, primarily from a 4.0%, or $5.3 million, decrease in the amount of mWh purchased offset by a 7.5%, or $2.6 million, increase in price.
The increase in energy costs for 1999 primarily resulted from increased Alliance purchases of $90.4 million, and an 8%, or $5.3 million increase in the amount of mWh purchased, offset by a $3.8 million decrease in price.
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 Millstone Unit #3. For additional information 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.
In 2000, production fuel costs increased $1.7 million pre-tax compared to 1999, primarily due to increased operation of the McNeil generating plant to support reliability due to an equipment failure in northern Vermont, and increased fuel costs.
For 1999, production fuel costs increased primarily due to increased generation by the Company's joint-ownership units.
Based on present commitments and contracts, the Company expects that net purchased power and production fuel costs will be approximately $143.7 million, $145.7 million and $151.4 million for the period 2001 through 2003.
Other operation expenses The decrease in other operation expenses of approximately $3.2 million versus 1999 and increase of $2.9 million in 1999 versus 1998, respectively, resulted primarily from decreased regulatory commission costs related to retail rates as well as decreased conservation and load management costs in 2000, primarily as a result of the EEU.
Maintenance expenses The decrease in maintenance expenses of $2.8 million in 2000 versus 1999 is primarily due to lower service restoration costs. The $2.0 million increase in 1999 versus 1998 is due to higher service restoration costs related to two major storms that occurred in 1999.
Income taxes Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences. For 2000 these taxes decreased as a result of a change in permanent differences for the period. Income taxes increased for 1999 as a result of an increase in pre-tax earnings and no change in permanent differences for the period.
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Other income and deductions Other income and deductions increased for 2000 and decreased for 1999. The increase in 2000 resulted from the positive impact of the nonrecurring gain related to the Millstone Unit #3 settlement, offset by an increase in the provision for income taxes. The decrease in 1999 was primarily due to lower equity income from non-utility subsidiary companies primarily related to SmartEnergy's proportionate share in HSS.
Interest on long-term debt In July 1999, the Company sold $75.0 million aggregate principal amount of 8 1/8% Second Mortgage Bonds due 2004. Accordingly, interest on long-term debt increased for 1999 and 2000. This increase was partially offset by the retirement of long-term debt in December 1998.
Other interest expense Other interest expense decreased for 2000 due to decreases in average outstanding short-term debt. In 1999, other interest expense increased due to increases in average outstanding short-term debt.
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 programs. Net cash flow provided by operating activities generated $60.9 million of cash in 2000, $31.2 million in 1999 and $21.7 million for 1998.
The Company ended 2000 with cash and cash equivalents of $48.0 million, an increase of $12.5 million from the beginning of the year. The increase in cash for 2000 was the result of $60.9 million provided by operating activities, offset by $20.4 million used for investing activities and $28.0 million used for financing activities.
Operating Activities - Net income and depreciation provided cash of $34.9 million. Approximately $26.0 million of cash was provided by working capital, and other operating activities including the impact of deseasonalized rates and the favorable Millstone Unit #3 settlement.
Investing Activities - Construction and plant expenditures used cash of approximately $15.0 million and C&LM programs used $1.1 million, while $4.6 million was used for non-utility investments and $0.3 million was provided by other investing activities.
Financing Activities - Dividends paid on common stock were $10.1 million, while preferred stock dividends were $1.8 million. Retirement of preferred stock required $1.0 million, and net retirement of long-term debt required $14.8 million of capital and reduction in capital lease obligations required $1.1 million. In addition, sale of common stock provided $0.5 million and other financing activities provided $0.3 million.
On July 30, 1999, the Company sold $75.0 million aggregate principal amount of 8 1/8% Second Mortgage Bonds due 2004 at a price of 99.915%. The net proceeds of the offering were used to repay $15.0 million of outstanding loans under the Company's revolving credit facility and are expected to be used for other general corporate purposes relative to the Company's utility business. In addition, the Company canceled its $40.0 million revolving credit facility.
The Company has an aggregate of $16.9 million of letters of credit with expiration dates of May 31, 2001.
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The Company's capital ratios (including amounts of long-term debt due within one year) for the past three years were as follows:
On February 2, 1999, Standard & Poor's Corporation ("Standard & Poor's") lowered its corporate credit rating on the Company to BBB- (triple-'B'-minus) from BBB (triple-'B'), the senior secured rating to BBB+ (triple-'B'-plus) from A- (single-'A'-minus), and the preferred stock rating to BB+ (double-'B'-plus) from BBB- (triple-'B'-minus). In addition, the ratings were also placed on CreditWatch with negative implications. On February 17, 1999, Standard & Poor's rating on the Company's preferred stock was automatically reduced to BB (double-'B') from BB+ (double-'B'-plus) in response to a policy change in the way Standard & Poor's rates preferred stock.
On March 28, 2000, Standard & Poor's reaffirmed that its ratings on the Company remain on CreditWatch with negative implications, reflecting the potentially adverse impact of pending legal and regulatory decisions that could seriously weaken the Company's credit profile.
In this regard, Standard & Poor's had the following excerpted comments:
"Standard & Poor's remains highly concerned about several important events, which are expected to occur in mid- to late-2000 and could result in significantly lower ratings. These events include the outcome of contract renegotiations with key power suppliers, most notably Hydro-Quebec, the arbitration related to the January 1998 ice storm, and a Vermont Supreme Court appeal, offset in part by the pending sale of the Vermont Yankee nuclear plant. Furthermore, if the PSB disallows the full recovery of power costs associated with the Hydro-Quebec contract, the utility may be required to record substantial write-offs. The outcome of key regulatory decisions will be the principal rationale for any rating or outlook adjustments.
CV's ratings reflect a below-average business profile, coupled with a weak financial profile for the current ratings when adjusted for off-balance-sheet power and transmission obligations. The utility's business profile reflects increasingly restrictive regulation, rising power costs, and nuclear asset exposure. This is tempered only partially by a diverse service area economy with limited industrial concentration, regionally competitive rates, and improving operational efficiency."
Standard & Poor's also said "resolution of the CreditWatch listing will depend on the Hydro-Quebec renegotiations, the arbitration related to the January 1998 ice storm, the Vermont Supreme Court appeal, and other state and federal legal proceedings, which could be resolved in mid- to late-2000. In addition, adequate rate relief and/or successful mitigation of high power costs through contract renegotiations or other methods are essential for maintaining ratings."
On February 17, 1999, Fitch, Inc. ("Fitch") formerly Duff & Phelps Credit Ratings Co., placed the credit ratings of the Company on Rating Watch-Down due to the high level of regulatory and public policy uncertainty in
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Vermont and the unfavorable ruling by the United States Court of Appeals relating to Connecticut Valley, the Company's wholly owned New Hampshire subsidiary.
On July 16, 1999, Fitch assigned a rating of "BBB-" (Triple-B-minus) to the Company's then proposed $75 million issue of second mortgage bonds and lowered its rating on the Company's preferred stock to "BB+" Double-B-plus) from "BBB-" (Triple-B-minus) with all ratings remaining on Rating Watch-Down.
On April 4, 2000, Fitch reaffirmed the Company's credit ratings and has maintained the ratings on Rating Watch-Down. Fitch had the following excerpted comments:
"The watch status reflects the continued high level of regulatory and public policy uncertainty in Vermont and the ultimate legal and regulatory outcome associated with the Company's wholly owned subsidiary, Connecticut Valley, which adds risk to the Company's financial profile going forward. Approximately $190 million of debt and preferred securities are affected."
Fitch also said, "The Company's ratings and watch status incorporate past negative rulings issued by the PSB regarding purchased power costs, which have led to financial instability and uncertainty among electric utilities in Vermont. Consequently, this uncertain public policy environment has directly impacted CV's overall credit quality, resulting in lower coverage ratios and reduced financial flexibility. Positively, CV has taken initiatives to offset the short-term financial and liquidity constraints of this regulatory induced situation. CV's recent second mortgage issuance (July 1999) provides the Company increased financial flexibility to meet its upcoming mandatory debt and preferred retirements over the next few years while a resolution to Vermont's above-market purchased power obligations, stranded cost recovery and ultimately industry restructuring is attained."
Current credit ratings of the Company's securities by Standard & Poor's and Fitch remain as follows:
Standard & Poor's (1)
Fitch (2)
Corporate Credit Rating
BBB-
N/A
First Mortgage Bonds
BBB+
BBB
Second Mortgage Bonds
BBB-
BBB-
Preferred Stock
BB
BB+
All Standard & Poor's ratings are on "CreditWatch with negative
implications."
All Fitch ratings are placed on "Rating Watch-Down." Fitch, Inc.
acquired Duff & Phelps Credit Ratings in June 2000.
In 1998, Catamount replaced its $8.0 million credit facility with a $25.0 million revolving credit/term loan facility maturing November 2006 which provides for up to $25.0 million in revolving credit loans and letters of credit, of which $21.6 million was outstanding at December 31, 2000.
In 1999, SmartEnergy Water Heating Services, Inc. ("SEWHS"), a wholly owned subsidiary of SmartEnergy, secured a $1.5 million, seven-year term loan with Bank of New Hampshire with an outstanding balance of $1.3 million at December 31, 2000. The interest rate is fixed at 9.50%.
Financial obligations of the Company's subsidiaries are non-recourse to the Company, although any future default under an arrangement for indebtedness of Catamount Energy or SEWHS, if unremedied, would trigger default under the Company's debt arrangements. Specifically, defaults under
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subsidiaries' debt instruments or subsidiary insolvencies can cause a default
under the Company's First Mortgage Bond Indenture, which would then cause cross-defaults to the Company's other debt arrangements. The Company will propose an amendment to its First Mortgage Bond Indenture which, if approved by the bondholders, would remove this potential risk of default caused by the Company's unregulated subsidiaries.
The Company cannot assure that its business will generate sufficient cash flow from operations or that future borrowing will be available to the Company in an amount sufficient to enable the Company to pay its indebtedness, including the $75.0 million second mortgage bonds, when due or to fund its other liquidity needs. The Company's ability to repay its indebtedness is, to a certain extent, subject to general economic, financial, competitive, legislative, regulatory, weather and other factors that are beyond its control. The type, timing and terms of future financing that the Company may need will be dependent upon its cash needs, the availability of refinancing sources and the prevailing conditions in the financial markets. The Company cannot guarantee that financing sources will be available to the Company at any given time or that the terms of such sources will be favorable.
Diversification
Catamount Resources Corporation was formed for the purpose of holding the Company's subsidiaries that invest in non-regulated business opportunities. Catamount Energy Corporation, a subsidiary of Catamount Resources Corporation, invests through its wholly owned subsidiaries in non- regulated energy generation projects in North America and Western Europe. Through its wholly owned subsidiaries, Catamount has interests in eight operating independent power projects located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; Thetford, England; Hopewell, Virginia; Thuringen, Germany and Fort Dunlop, England. In addition, Catamount has interests in a project under construction in Summersville, West Virginia and in Mecklenburg-Vorpommern, Germany. In November 1999, Catamount partnered with CIT Group, a major equipment finance company, and Dana Commercial Credit Corporation, the finance subsidiary of Dana Corporation to form Catamount Investment Company, which intends to invest in independent power projects in North America and Western Europe. An affiliate of Catamount Investment Company closed on a transaction to purchase the Eckolstadt Windfarm, located in Thuringen, Germany and the planning rights to the Kavelstorf Windfarm in Mecklenburg-Vorpommern, Germany in December 2000. Catamount has committed to a $2.1 million letter of credit as well as a security interest in its stock, securing the payment of potential cost overruns at the Gauley River Power project which is currently behind schedule. Catamount's after-tax earnings were $.7 million, $2.1 million, and $3.3 million for 2000, 1999 and 1998, respectively.
SmartEnergy, also a subsidiary of Catamount Resources Corporation, invests in unregulated energy and service related businesses. Overall, SmartEnergy incurred net losses of $2.3 million, $2.9 million and $1.5 million for 2000, 1999 and 1998, respectively. SmartEnergy also has a 27.9% ownership interest, on a fully diluted basis, in The Home Services Store ("HSS"), as of December 31, 2000, which is accounted for using the equity method. HSS establishes a network of affiliate contractors who perform home maintenance repair and improvements via membership. HSS began operations in 1999 and is subject to risks and challenges similar to a company in the early stage of development. SmartEnergy's share of HSS's pre-tax loss for 2000 and 1999 was $3.7 million and $5.3 million respectively.
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HSS began a limited rollout through Sam's Club in the second quarter of 1999. After this successful test, a national rollout was commenced at the end of 1999. A nationwide rollout was also commenced in 2000 with TruServ Corporation (True Value Hardware Stores). As of February 2001, HSS is available in approximately 150 markets in the United States.
On March 14, 2000, HSS issued 3,500,000 shares of convertible preferred stock. The proceeds of approximately $32.0 million, net of transaction costs, is being used by HSS to finance the national rollout of HSS. On October 4, 2000, in a stock transaction, HSS acquired ServiceBeyond.Com, a web-based home services management company serving the San Diego, Denver and Dallas markets. As of December 31, 2000, SmartEnergy's net investment in HSS is $1.9 million. On January 3, 2001, HSS raised an additional $10.0 million through the issuance of additional convertible preferred stock. SmartEnergy's ownership interest is currently 26.3% on a fully diluted basis.
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 automatically passed on to consumers through rate adjustment clauses. The Company intends to continue its practice of periodically reviewing costs and requesting rate increases when warranted.
Vermont Retail Rate Proceedings
1997 Retail Rate Case: 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.
In response to the Company's September 1997 rate increase filing, the PSB decided to appoint an independent investigator to examine the Company's decision to buy power from Hydro-Quebec. The Company made a filing with the PSB stating that the PSB as well as other parties should be barred from reviewing past decisions because the PSB already examined the Company's decision to buy power from Hydro-Quebec in a 1994 rate case in which the Company was penalized for "improvident power supply management". During February 1998, the DPS filed testimony in opposition to the Company's retail rate increase request. The DPS recommended that the PSB instead reduce the Company's then current retail rates by 2.5% or $5.7 million. The Company sought, and the PSB granted, permission to stay this rate case and to file an interlocutory appeal of the PSB's denial of the Company's motion to preclude a re-examination of the Company's Hydro-Quebec contract in 1991. The Company has argued its position before the Vermont Supreme Court.
1998 Retail Rate Case: On June 12, 1998, the Company filed with the PSB for a 10.7% retail rate increase that supplanted the September 22, 1997 rate increase request of 6.6%, to be effective March 1, 1999. On October 27, 1998, the Company reached an agreement with the DPS regarding the June 1998 retail rate increase request providing 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 on or after January 1, 1999. The agreement was approved by the PSB on December 11, 1998.
The 4.7% rate increase is subject to retroactive or prospective adjustment upon future resolution of issues arising under the Hydro-Quebec and Vermont Joint Owner's ("VJO") Power Contract. The agreement temporarily
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disallows approximately $7.4 million (based on 1999 power costs) for the Company's purchased power costs under the VJO Power Contract. As a result of the 4.7% rate increase agreement, during the fourth quarters of 1998, 1999 and 2000, the Company recorded pre-tax losses of $7.4 million, $2.9 million, and $2.9 million, respectively, for disallowed purchased power costs, representing the Company's estimated under recovery of power costs, prior to further resolution, under the VJO Power Contract for 1999, the first quarter of 2000, and the first quarter of 2001, respectively. An additional $11.5 million pre-tax loss was recorded in 2000 for the estimated under recovery of Hydro-Quebec power costs for the second, third, and fourth quarters of 2000 and the first quarter of 2001. If, in the future, the Company is unable to increase rates to recover the temporary disallowed purchased power costs prior to further resolution under the VJO Power Contract or otherwise mitigate these costs, the Company would be required to record losses for any estimated future under recovery.
These temporary disallowances were calculated using comparable methodology to that used by the PSB in the GMP rate case on February 28, 1998. In that case, the PSB found GMP's decision to commit to the VJO Power Contract in 1991 "imprudent" and that power purchased under it was not "used and useful". As a result, the PSB concluded that a portion of GMP's current costs should not be imposed on GMP's customers and were disallowed. GMP appealed the rate order to the Vermont Supreme Court. Should the Company receive a similar order from the PSB, the Company would experience a material adverse effect on its results of operations and financial condition.
In January 2001, the PSB issued an order that resulted in a 3.42% rate increase for GMP and also made permanent its two temporary rate increases that were already in effect for that company. This PSB Order results in the treatment of GMP's portion of the VJO Power Contract as if its share of the contract is "prudent" and "used and useful". This PSB Order only applies to GMP. In addition, GMP agreed to withdraw its Vermont Supreme Court appeal regarding the VJO contracts described above.
On February 9, 2001, the Vermont Supreme Court issued a decision on the Company's 1998 rate case appeal that reversed the PSB's decision on the preclusion issues and remanded the case to the PSB for further proceedings consistent with the Vermont Supreme Court's decision. However, if the PSB subsequently issues a final rate order adopting the disallowance methodology used to determine the temporary Hydro-Quebec disallowance described above for the duration of the VJO Power Contract, the Company would not be able to recover approximately $179.7 million of power costs over the life of the contract, including $11.3 million in 2001 and $11.4 million in 2002, $11.5 million in 2003, $11.7 million in 2004 and $11.8 million in 2005. In such an event, the Company would be required to take an immediate charge to earnings of approximately $179.7 million (pre-tax). Such an outcome could jeopardize the Company's ability to continue as a going concern. However, at this time, the Company does not believe that such a loss is probable particularly in view of the January 2001 PSB Order issued in GMP's proceedings, and the decision of the Vermont Supreme Court's reversing and remanding the PSB's order.
Deseasonalized Rates: On April 13, 2000, the Company and the DPS filed a stipulated agreement with the PSB to end winter-summer rate differentials for the Company's Vermont customers. On June 8, 2000, the PSB approved the Company's request to end the winter-summer rate differential and, therefore, the Company will now have flat rates throughout a given year. Winter rates were reduced by 14.9%, while summer rates were increased 10.5%. The rate design change will be revenue neutral over a 12-month period. The additional 2000 revenues, resulting from implementing this change in mid-year, have been
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applied to reduce or eliminate certain regulatory deferrals, as directed by the PSB.
2000 Retail Rate Case: In an effort to mitigate projected eroding earnings and cash flow prospects in the near future, due mainly to under recovery of its Hydro-Quebec power costs, on November 9, 2000, the Company filed with the PSB a request for a 7.6% rate increase ($19.0 million of annualized revenues) to be effective July 1, 2001. In the request the Company also asked for the PSB to find that the Company's share of the VJO Power Contract be found to be "prudent" and "used and useful".
The PSB suspended the rate filing and a schedule has been set to review the rate case. An order from the PSB is expected before July 24, 2001. The company is engaged in settlement discussions with the DPS in an effort to settle the 2000 retail rate case. The Company cannot predict the outcome of those settlement discussions or the ultimate outcome of this rate case.
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. See Note 13 to the Consolidated Financial Statements for further discussion.
Proposed Formation of Holding Company
In order to further prepare the Company for deregulation, and to insulate the Company from the risks of its various regulated and unregulated subsidiaries, 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 reduce the Company's Vermont utility's cost of capital and thus will be beneficial to its ratepayers. It will also benefit any future transition to a deregulated electricity market in Vermont. The proposed holding company formation must also be approved by Federal regulators, including the Securities and Exchange Commission, the FERC, various States and by the Company's shareholders. The Company has negotiated an agreement with the DPS regarding code of conduct and affiliate transaction rules to be utilized once a holding company structure is implemented. The Company has informed the PSB that it is prepared to present the Code of Conduct and affiliate transaction rules to the PSB for it's review and approval, while the DPS has informed the PSB that it prefers to defer the PSB's review until other regulatory issues are resolved.
ELECTRIC INDUSTRY RESTRUCTURING
The electric utility industry is in a period of transition that may result in a shift away from rate making based on cost of service and return on equity to more market-based rates with energy sold to customers by competing retail energy service providers. 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. Recent events, including those related to restructuring in California have resulted in the slowdown of the restructuring process in Vermont.
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Vermont
Recently, there have been three primary sources of Vermont governmental activity in attempting to restructure the electric industry in Vermont: (1) the Governor's Working Group, created by the Governor of Vermont; (2) the PSB's Docket No. 6140 through which the PSB considered restructuring proposals; and (3) the PSB's Docket No. 6330, through which the PSB is considering the establishment of policies and procedures to govern retail competition within the Company's service territory.
The Working Group
On July 22, 1998, the Governor of Vermont issued an Executive Order establishing the Working Group on Vermont's Electricity Future 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 could 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 the Governor to gather information on and evaluate the possible consequences of the current financial status of Vermont electric utilities.
A report was issued by the Working Group on December 18, 1998. Key conclusions of the report were:
The bankruptcy of Vermont electric utilities should not be viewed as an appropriate means to reduce Vermont utilities' committed power supply costs.
Vermont should restructure its electric industry by moving rapidly to retail choice whereby consumers would purchase power directly from competing power suppliers.
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.
The Vermont electric utilities should pursue auctions of their power generation assets and remaining power contracts.
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 some of the highest electricity rates in the nation, electricity costs in Vermont have been among the lowest in the region, although the Company's rates are higher than the Vermont average. However, that advantage is eroding as other states in New England restructure their electric utility industries. Therefore, the Working Group noted that it is in the interest of Vermont ratepayers to have the benefit of a restructured electric utility industry as soon as possible.
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Public Service Board Docket No. 6140
On September 15, 1998, the PSB opened 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 intended that this proceeding define one or more acceptable courses for power supply reform. All Vermont utilities were made a party to the 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.
On March 3, 1999, the Company filed its Restructuring Plan, a Working Plan to restructure a significant portion of Vermont's Electric Utility Industry, with the PSB and parties in Docket No. 6140. The Company's plan was a joint plan with GMP. On July 12, 1999, the PSB issued a Status Order concluding that the objective of implementing power supply reform may be advanced more effectively in ways other than holding further technical conferences in the docket. Absent good reason to hold one or more technical conferences pertinent to power supply reform, the PSB indicated that the docket would be closed on December 31, 1999, which action has occurred. As a companion proceeding to its Docket No. 6140 investigation, on January 19, 1999, the PSB issued an order opening a new contested case proceeding, Docket No. 6140-A, where it indicated that it intended to issue final, binding and appealable orders concerning matters related to the reform and restructuring of Vermont's electric utility industry. Initially, the PSB notified 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 consider the principles, authority and proposals for reform of Vermont's electric power supply. This included issues associated with the scope and extent of the PSB's authority to approve "securitization" and other financing 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.
By Order dated June 24, 1999 in Docket 6140-A, the PSB formally adopted the Vermont Principles on Electric Utility Restructuring. The Order explains that proposals to open utility franchise service areas to retail competition, including the company's Restructuring Plan, will only be approved if they can be found to satisfy the public good after due consideration is given to each of 14 Restructuring Principles. If one or more of the principles is not satisfied by the proposal, then the proponent must offer justification for the deficiency and demonstrate satisfaction of certain statutory requirements. As such, the PSB stated that any filing proposing to open a franchise territory to retail choice would have to be supported, at a minimum, by an explanation of how that proposal fulfills the policy objectives established by the Vermont Principles on Electric Utility Restructuring.
With regard to financing, no party to the investigation asked that the PSB clarify its authority or issue a declaratory ruling concerning the criteria to be considered when approving utility financing for the buy-out or buy-down of committed power contracts. During the investigation, both the Company and GMP asserted that anticipated refinancing approaches could be accomplished utilizing the existing Vermont and federal legislative regime that governs the regulation of electric utilities and that "securitization" style financing were not presently being contemplated. Because no party to
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the Docket contradicted these statements, the PSB accepted our assertions and took no further action to evaluate specific utility financing proposals.
In contrast, Vermont Electric Power Producers, Inc. ("VEPP"), purchasing agent for the purchase of power from qualifying facilities pursuant to PSB Rule 4.100, proposed to use administrative securitization to finance the reform of its power purchase contracts. However, at the request of all commenting parties, the PSB determined to withhold judgment on the issue as to whether the PSB had jurisdiction to authorize a VEPP financing until such time as a specific proposal was actually filed with the PSB. In the absence of any requests for further investigation or action to be filed within 30 days of the Docket No. 6140-A Order, the PSB indicated that this investigation would be closed, which action has occurred. To follow up on its proposal, on June 15, 2000, VEPP filed a petition requesting that the PSB issue a declaratory ruling confirming the authority of the PSB to issue voluntary administrative securitization orders relative to those qualifying facilities currently holding purchase power contract under PSB Rule 4.100. By order dated June 30, 2000 the PSB opened Docket No. 6396. As part of the Docket proceedings, the PSB convened a workshop to hear detailed presentations on the VEPP proposal. Parties to the Docket filed their positions on the Board's authority to issues related to the requested ruling in mid-November. On January 10, 2001, the PSB convened an oral argument on the VEPP financing proposal. A final order in that proceeding is expected within the first quarter of 2001.
The Company supports the Working Group recommendations described above and believes that the restructuring of the electric industry is essential to improve its financial position, enhance its ability to effectively compete in a changing electric utility industry and stabilize projected costs.
As a result, the Company is pursuing a comprehensive financial Restructuring Plan, certain elements of which were included in the Plan that the Company and GMP filed with the PSB in the first quarter of 1999 in connection with the proceedings in Docket No. 6140 described above. The Company is aggressively pursuing implementation of the Restructuring Plan which includes the following elements:
Retail choice:
voluntarily giving up the exclusive right to supply power to the Company's present electric customers, while retaining its rights as a distribution company, as part of a global settlement of regulatory issues.
Renegotiation of certain purchased power contracts:
reducing the Company's future cost of power by renegotiating power contracts, specifically those with Hydro-Quebec and the Vermont purchasing agent's contracts with IPPs which together represent approximately 40% of the Company's 1998 net energy supply. The Company may seek to finance the cost of any buy-outs or buy-downs of power contracts through the future issuance of securities in the capital markets.
Contract and asset disposition:
seeking to sell power purchase contracts and generating assets, including the Company's interest in the Vermont Yankee nuclear generating plant. On October 15, 1999, the Company and the other owners of Vermont Yankee accepted a bid for sale of the plant to AmerGen Energy Company ("AmerGen"), which is owned by PECO Energy Company and British Energy. This transaction would have also involved taking back a contract to purchase a portion of the power produced by this plant. The Vermont Yankee sale still needed to be approved by the PSB. On November 4, 1999 the PSB opened Docket No. 6300 to consider the issues attendant to the approval of the sale of
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Vermont Yankee and approval of various related agreements including the Company's agreement to continue to purchase its share of the output of Vermont Yankee. During the course of the PSB's proceedings, the DPS, AmerGen and the owners of Vermont Yankee proposed a settlement to the docket issues that would have increased the purchase price to be realized pursuant to the sale of the Vermont Yankee plant. When the PSB initiated proceeding on the settlement, another potential purchaser, Entergy, announced its interest in purchasing the facility. In mid-January 2001, Entergy proposed a price for the purchase of the Vermont Yankee plant that exceeded the price set forth within the settlement. The DPS subsequently announced that it no longer supported the settlement and filed such notice with the PSB. Based on the bid by Entergy, plus the indications of interest in the Vermont Yankee plant by Dominion Resources and Constellation Energy, the Company noticed the PSB that recent developments caused the Company to conclude that the settlement no longer represented the best market value option when compared to the likely (but not guaranteed) outcome of a timely auction of the plant. This process is expected to take place over the next several months with the goal of reaching a conclusion by the end of 2001,if possible.
Cost-cutting:
implementing cost-cutting measures to reduce cash flow requirements while maintaining safety and reliability standards.
Holding company:
establishing a holding company in order to further prepare the Company for deregulation.
Industry consolidation:
evaluating possible consolidations with other Vermont electric distribution companies.
Regulatory settlement:
seeking a comprehensive regulatory settlement that leads to long-term financial stability.
Energy efficiency activities:
creating a state sponsored "energy-efficiency utility" to take over most system-wide energy-efficiency services for electric customers. On September 30, 1999, the PSB issued a final order approving a Memorandum of Understanding between the Company, the DPS, all other Vermont electric utility companies and other interested parties that calls for the establishment of the energy-efficiency utility and provides for its funding via a separate stated Energy Efficiency Charge. As of March 2000, system-wide energy-efficiency services are provided to the Company's customers by Efficiency Vermont, the contractor selected by the PSB to serve as the energy-efficiency utility. The Company believes that implementation of its Restructuring Plan is a critical element to improving its future financial performance and to providing its customers with more stable electric rates and the continuation of efficient and reliable electric service. The key contingency of the Company's Restructuring Plan is regulatory approval of a rate schedule that will allow the Company to recover the costs of the restructuring. If the financial restructuring described in this section is completed in conjunction with the deregulation of Vermont's electric industry described in "Electric Industry Restructuring," the Company anticipates that its utility financial performance and prospects will improve significantly.
Public Service Board Docket No. 6330
On November 23, 1999, the Company and GMP (together the "Companies") filed a joint Petition and Supporting Materials with the PSB asking that the
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PSB open an investigation to establish retail access policies and procedures to resolve issues that must be decided to implement the Companies' Restructuring Plan. Specifically, the Petition requests that the PSB issue such orders and approvals as are necessary or advisable to:
permit the Companies to suspend their provision of power supply
services ("Generation Service") to customers located within their
respective service territories;
permit the Companies to amend their service tariff obligations to
clarify that they retain their exclusive service franchises as providers of electric delivery services ("Delivery Service") to customers within their respective service territories;
permit the Companies to implement a Retail Open Access Tariff
("ROAT") that enables customers located within the Companies' respective service territories to choose their power supplier from an array of approved energy service providers ("ESP"), and to purchase Generation Service from such ESPs at market-determined prices;
select through a competitive bidding process an ESP or ESPs to
deliver "Default Service" for energy to customers located within the Companies' service territories; that do not otherwise have an arrangement with an ESP for the provision of Generation Service;
select through a competitive bidding process an ESP or ESPs to deliver "Transition Service" for energy to customers located within the Companies service territories; and
approve revisions and modifications to the Companies' tariffs to
implement voluntary retail access within the Companies' respective service territories as provided for pursuant to this Petition.
The consent to retail access within the Companies' service areas established by the Petition is voluntary and conditional. Pursuant to the Petition, the Companies' consent to customer choice and retail competition is expressly conditioned upon approval of all elements of the Companies' Restructuring Plan including the approval of any proposed mitigation measures to reduce power costs and financing measures related thereto, and a mechanism to recover the costs rendered stranded on account of the move to retail access and customer choice.
On January 14, 2000, the PSB opened Docket No. 6330 to consider the issues raised by the Companies' petition. In its opening Order, the Board states:
"The scope of this investigation is intended to address many of the more detailed aspects of retail open access. While current law may not permit this Board to require retail open access of Vermont utilities, the companies are clearly able to open their service territories on a voluntary basis. Whether retail open access is established on a voluntary basis through existing statutes or through revised legislation, there are many technical issues to be resolved. This investigation will serve to advance many aspects of issues surrounding retail open access."
An initial pre-hearing conference was held in this investigation on January 31, 2000. The parties to Docket No. 6330 have agreed to consider the Companies proposal in a proceeding consisting of two phases. In Phase I
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parties will identify the scope and extent of consensus on docket issues (Module 1) and attempt to negotiate agreements on matters where consensus does not initially emerge (Module 2). In Phase II, parties will litigate unresolved issues. As part of the Phase I, Module 1, activities, the PSB convened an extensive two-day education conference to hear presentations on the lessons learned in other jurisdictions and to fill information voids identified by Docket participants during approximately 25 education working group sessions held in the proceeding during much of calendar year 2000. At this time, it is premature to predict the date upon which a final PSB resolution of the matters raised in this investigation will be decided. Note that the Companies proposed an initial start date for retail competition when all of the elements of the joint Restructuring Plan are completed.
New Hampshire - FERC Proceedings
The Company filed an application with the FERC in June 1997, to recover stranded costs in connection with its wholesale rate schedule with Connecticut Valley and a notice of cancellation of the Connecticut Valley rate schedule (contingent upon the recovery of the stranded costs that would result from the cancellation of this rate schedule). In December 1997, the FERC rejected the Company's proposal to recover stranded costs through the imposition of a surcharge on our transmission tariff, but indicated that it would consider an exit fee mechanism for collecting stranded costs. The FERC denied the Company's motion for a rehearing regarding the surcharge proposal, so the Company filed a request with the FERC for an exit fee mechanism to collect the stranded costs resulting from the cancellation of the contract with Connecticut Valley. The stranded cost obligation sought to be recovered through an exit fee, expressed on a net present value basis as of December 31, 2000, is approximately $41.5 million. 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. During April and May 1999, nine days of hearings were held at the FERC before an Administrative Law Judge, who will determine, among other things, whether Connecticut Valley qualifies for an exit fee, and if so, the amount of Connecticut Valley's stranded cost obligation to be paid to the Company as an exit fee. The ruling of the Administrative Law Judge could be issued at any time. Thereafter, the FERC will act on the judge's recommendations.
If the Company is unable to obtain an order authorizing the recovery of costs in connection with the June 1997 FERC filing or in the Federal Court, it is possible that the Company would be required to recognize a pre-tax loss under this contract totaling approximately $44.7 million as of December 31, 2000. The Company would also be required to write-off approximately $1.5 million (pre-tax) in regulatory assets associated with its wholesale business as of December 31, 2000. If the Company obtains a FERC order authorizing the updated requested exit fee, Connecticut Valley will have to apply to the NHPUC to increase rates in order to pay the exit fee. The Company believes that the NHPUC must permit Connecticut Valley to raise rates to recover the cost of the exit fee. However, if Connecticut Valley is unable to recover its costs by increasing its rates, Connecticut Valley would be required to recognize the loss discussed above.
In addition to its efforts before the Court and FERC, Connecticut Valley has initiated efforts and will continue to work for a negotiated settlement with parties to the New Hampshire restructuring proceeding and the NHPUC.
An adverse resolution of these proceedings would have a material adverse effect on the Company's results of operations and cash flows. However, the
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Company cannot predict the ultimate outcome of this matter. See Note 13 to the Consolidated Financial Statements for additional information related to New Hampshire Retail Rates.
Connecticut Valley constitutes approximately 7% of the Company's total retail mWh sales.
Regional Transmission Organizations (RTO)
Pursuant to FERC Order No. 888 (issued April 1996) the Company operates their transmission system under an open access, nondiscriminatory transmission tariff.
On May 13, 1999, the FERC issued a notice of proposed rulemaking that would amend FERC's regulations under the Federal Power Act to facilitate the formation of regional transmission organizations ("RTO"). On December 20, 1999, the FERC issued Order No. 2000, which requires all public utilities that own, operate, or control interstate electric transmission to file a proposal for an RTO by October 15, 2000, or in the alternative, a description of any efforts by the utility to participate in an RTO, the reasons for not participating and any obstacles to participation, and any plans for further work toward such participation. The filing date for Order No. 2000 was extended to January 16, 2001 for utilities in regions with an existing independent system operator ("ISO"), e.g. ISO-New England.
The Company, jointly with GMP, Citizens Utilities and Vermont Electric Power Co. ("VELCO"), filed its comments on the New England RTO proposal submitted by some of the New England transmission owners and ISO-NE on January 16, 2001. Order No. 2000 anticipates operational RTOs by December 15, 2001. The Company will continue to negotiate with the New England transmission owners in continuing to develop an RTO which meets the requirements of Order No. 2000. At this time, the Company has several options for joining an RTO, some of which do not require a transfer of assets. There can be no assurance as to the outcome of this matter.
Competition - Risk Factors
If retail competition is implemented in Vermont or New Hampshire, the Company is unable to predict the impact on its revenues, the Company's ability to retain existing customers with respect to their power supply purchases and attract new customers or the margins that will be realized on retail sales of electricity, if any such sales are sought. The Company expects its power distribution and transmission service to its customers to continue on an exclusive basis subject to continuing economic regulation.
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. Statement of Accounting Standards, ("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 $45.8 million
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on a pre-tax basis as of December 31, 2000. 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 as 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, 2000 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 3.4% for 2000, 2.2% for 1999 and 1.6% for 1998. The Company's revenues, however, are based on rate regulation that generally recognizes
only historical costs. Inflation therefore continues to have an impact on most aspects of the business.
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Recent Accounting Pronouncements In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. In June 1999, the FASB issued Statement No. 137, Accounting for Derivative Instruments and Hedging Activities -- Deferral of the Effective Date of SFAS No. 133 and in June 2000, issued SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Activities, an amendment to FASB Statement No. 133. These Statements establish 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. These Statements require 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, as amended, is effective for fiscal years beginning after June 15, 2000. 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. With respect to hybrid instruments, a company may elect to apply SFAS No. 133, as amended, to (1) all hybrid contracts, (2) only those hybrid instruments that were issued, acquired, or substantively modified after December 31, 1997, or (3) only those hybrid instruments that were issued, acquired, or substantively modified after December 31, 1998.
The Company has completed its review and implementation of SFAS No. 133, effective January 1, 2001. The Company has taken an inventory of its contracts and determined that two of its contracts are derivatives under SFAS No. 133. One contract is a long term purchased power contract that allows the seller to purchase specified amounts of power with advance notice. Based on the application of rate regulated accounting principles, this contract is not expected to have an impact on stockholders' equity or net income. The second contract is an interest rate swap, which qualifies for hedge accounting under SFAS No. 133 and is not expected to have a material impact on stockholders' equity.
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Item 8.
Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements and Supplementary Data
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Report of Independent Public Accountants
To the Board of Directors of
Central Vermont Public Service Corporation:
We have audited the accompanying consolidated balance sheets and statements of capitalization of Central Vermont Public Service Corporation and its wholly-owned subsidiaries (the Company) as of December 31, 2000 and 1999, 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, 2000. 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 auditing standards generally accepted in the United States. 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, 2000 and 1999 and the results of their operations and cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States.
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. The Vermont Supreme Court (VSC) has reviewed the Company's claim that the PSB is precluded from again trying the Company on certain Hydro-Quebec contract issues. The VSC issued an order on February 9, 2001 that reversed the PSB's decision on the preclusion issues and remanded the case back to the PSB for further proceedings consistent with the VSC's decisions. If the ultimate resolution of these PSB 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 5, 2001 (except with respect to the matter discussed
in Note 13, as to which the date is February 9, 2001)
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CONSOLIDATED STATEMENT OF INCOME
(Dollars in thousands, except per share amounts)
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in thousands)
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CONSOLIDATED BALANCE SHEET
(Dollars in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENT OF CAPITALIZATION
(Dollars in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCK EQUITY
(Dollars in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
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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 PSB, the NHPUC and the 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 No. 71, or SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," for both the Company's 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, this accounting standard would 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 future recovery of its regulatory assets in the State of Vermont for the Company's retail business is probable. 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, in 1998, management discontinued the application of regulatory accounting principles applied to Connecticut Valley. As such, in 1998, Connecticut Valley wrote off regulatory assets of approximately $1.3 million on a pre-tax basis. For additional information see Note 13 below.
Unregulated Business Results of operations of the Company's two wholly owned non-regulated subsidiaries, Catamount and SmartEnergy, 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 associated with investments in new projects. Catamount's project 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 each quarterly accounting period. For 2000 and 1999, operating revenues include $22.2 million and $100.1 million related to the Alliance with Virginia Power, which was effectively terminated by the Company during the third quarter of 1999.
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
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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 3.54%, 3.54% and 3.57% of the cost of depreciable utility plant for each of the years 1998 through 2000, respectively.
Income Taxes In accordance with SFAS No. 109, "Accounting for Income Taxes" the Company 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. 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 or 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 ratemaking proceedings. AFDC equity represents a current non-cash credit to earnings, recoverable over the life of the property. The AFDC rates used by the Company were 8.62%, 5.52% and 9.30% for the years 1998 through 2000, respectively.
Regulatory Assets Certain costs are deferred and amortized in accordance with authorized or expected ratemaking treatment. The major components of regulatory assets reflected in the Consolidated Balance Sheet as of
December 31, are as follows (dollars in thousands):
Conservation and load management
$10,212
$13,173
Restructuring costs
2,472
3,757
Nuclear refueling outage costs
1,928
8,149
Income taxes
7,047
8,429
Year 2000 costs and technologies initiatives
2,322
2,766
Dismantling costs:
Maine Yankee nuclear power plant
11,505
12,785
Connecticut Yankee nuclear power plant
5,446
8,351
Yankee Atomic nuclear power plant
-
Hydro-Quebec arbitration costs, net of deseasonalized
revenue impact for 2000
2,531
1,970
Unrecovered plant and regulatory study costs
1,510
1,700
Other regulatory assets
$45,797
$62,808
The Company earns a return on unamortized Conservation and Load Management ("C&LM"), replacement energy and maintenance costs. During regular nuclear refueling outages, the incremental costs attributable to replacement energy purchased from NEPOOL or other parties in New England and maintenance costs are deferred and amortized ratably to expense until the next regularly scheduled refueling shutdown. 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.
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In addition, the Company is not earning a return on approximately $5.6 million of restructuring, Year 2000 and other unamortized regulatory assets being recovered over periods ranging from 2 to 33 years. The recovery of $2.5 million of Hydro-Quebec arbitration costs, net of incremental revenues due to implementation of deseasonalized rates on July 1, 2000, will be determined in the pending rate proceeding.
Purchased Power The Company records the annual cost of power obtained under long-term contracts as operating expenses. Since these contracts, 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. For 2000 and 1999, purchased power includes $22.0 million and $100.6 million, respectively, related to the Alliance with Virginia Power, which was effectively terminated by the Company during the third quarter of 1999.
Valuation of Long-Lived Assets The Company periodically evaluates the carrying value of long-lived assets and long-lived assets to be disposed of, including its investments in nuclear generating companies and its interests in jointly owned generating facilities, when events and circumstances warrant such a review. The carrying value of such assets is considered impaired when the anticipated undiscounted cash flow from such an asset is separately identifiable and is less than its carrying value. In that event, a loss is recognized based on the amount by which the carrying value exceeds the fair market value of the long-lived asset. Based on management's estimates, no impairment of long-lived assets exists as of December 31, 2000.
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 an original maturity of three months or less when acquired to be cash equivalents.
Note 2
Investments in affiliates
The Company uses the equity method to account for its investments in the following companies (dollars in thousands):
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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):
Date of
Study
Total
Estimated
Obligation
CVPS
Obligation
Obligation
Nuclear generating companies:
Vermont Yankee
$312.7
$ 109.4
Maine Yankee
$536.0
$ 10.7
Connecticut Yankee
$588.0
$ 11.8
Yankee Atomic
$461.0
$ 16.1
Vermont Yankee
Vermont Yankee's current decommissioning cost study is based on a 1994 site study, stated in 1993 dollars. The FERC approved settlement agreement allowed $312.7 million as the estimated decommissioning cost. Based on the study's assumed cost escalation rate of 5.4% per annum and an expiration of the plant's operating license in the year 2012, the estimated current cost of decommissioning is $451.8 million and, at the end of 2012, is approximately $815.2 million. The current value of the pro rata portion of decommissioning costs recorded to date is $321.4 million, of which the Company's share is $112.5 million.
Under the FERC approved settlement agreement, Vermont Yankee was required to file with FERC an updated decommissioning cost study by April 1, 1999. On May 13, 1999, in light of the ongoing discussions involving the possible sale of the Vermont Yankee nuclear power plant, the FERC approved a settlement agreement extending the required filing date. If the plant is not sold to AmerGen or in an auction, Vermont Yankee will need to submit a new decommissioning filing to the FERC. The sale of the plant would transfer responsibility for decommissioning the plant to the new owner and make a revised schedule of decommissioning unnecessary.
On November 16, 2000, Vermont Yankee executed a revised Asset Purchase Agreement with AmerGen. The sale of the nuclear generating plant would transfer responsibility for decommissioning the plant to the new owner. Additionally, Vermont Yankee's current owners would make a one-time payment currently estimated at $37.0 million to pre-pay the plant's decommissioning fund. In return, AmerGen would assume full responsibility for all future operating costs and the estimated $815.2 million cost for decommissioning the plant at the end of its operating license in 2012. This agreement also involves the Company entering into a contract to purchase a portion of the power produced by this plant. In addition, Entergy submitted two bids to the PSB. The indications of interest in the Vermont Yankee plant by Entergy, Dominion Resources and Constellation Energy; and other nuclear plant sales, provide support for the Company's conclusion that the revised AmerGen transaction no longer represents the best market value option when compared to the likely (but not guaranteed) outcome of a timely auction. The DPS filed its notice to the PSB that the DPS no longer supports the revised agreement with AmerGen.
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On February 14, 2001, the Public Service Board issued its Order Dismissing Petition in Docket No. 6300, the proceeding in which the Company, along with GMP, Vermont Yankee and AmerGen sought Board approval of the sale of the Vermont Yankee nuclear plant to AmerGen. In this Order, the Board determined that the proposed purchase price, as filed in November 2000 pursuant to a Memorandum of Understanding, did not reflect the fair market value of the plant and, therefore, the sale did not promote the general good of the State of Vermont. Subject to certain procedural matters, the PSB will dismiss the petition for approval. This ruling is consistent with the Company's position. The Company will participate with Vermont Yankee management to determine whether an auction best serves the interests of the Company; other possible outcomes include continuing to own and operate the plant, selling the plant to Entergy in accordance with their proposals, or prematurely retiring the plant from service. This process is expected to take place over the next several months with the goal of reaching a conclusion by the end of 2001, if possible.
Maine Yankee
In 1997, the Maine Yankee 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 $558.9 million including a decommissioning obligation of $252.5 million, as of December 31, 2000.
FERC approved an Offer of Settlement filed by Maine Yankee and the active intervenors on January 19, 1999. As a result, 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 are resolved. Also resolved are 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.
Connecticut Yankee
In 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.
Connecticut Yankee reached a settlement with the FERC and the intervenors allowing for the cost recovery of the expected decommissioning costs now estimated at $588.0 million in January 2000 dollars, as well as other appropriate costs of service. The settlement rates became effective September 1, 2000, following the FERC order of July 26, 2000.
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.
As of July 2000, Yankee Atomic has collected from its sponsors sufficient funds, based on a current forecast, to complete the decommissioning effort and to recover all other FERC approved costs of service. Therefore, Yankee Atomic has discontinued billings to its sponsors pending the need to increase or decrease the funds available for the completion of its financial obligations including decommissioning. Such a change would require a FERC review and approval.
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Maine Yankee, Connecticut Yankee and Yankee Atomic Decommissioning Costs
Currently, 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. As of December 31, 2000, the Company has completed its obligation for decommissioning costs based on current estimates related to Yankee Atomic. The Company's share of remaining costs with respect to Maine Yankee and Connecticut Yankee's decisions to discontinue operation, including the costs in the table above, is estimated to be $11.5 million and $5.4 million, respectively, at December 31, 2000. These amounts are subject to ongoing review and revisions, and are reflected in the accompanying Consolidated Balance Sheet both as regulatory assets and nuclear dismantling liabilities (current and non-current).
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 believed that the decision to close the plants would lower committed costs and was in its customers' best interest. 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 $9.5 billion. Beyond that a licensee is indemnified under the Price-Anderson Act, 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 $9.3 billion per incident by assessing $88.1 million against each of the 106 reactor units that are currently subject to the Program in the United States, limited to a maximum assessment of $10.0 million per incident per nuclear unit in any one year. The maximum assessment is adjusted at least every five years to reflect inflationary changes. Currently 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.
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Vermont Yankee
Summarized financial information for Vermont Yankee Nuclear Power Corporation is as follows (dollars in thousands):
Earnings
Operating revenues
$178,294
$208,812
$195,249
Operating income
$ 16,144
$ 14,932
$ 15,282
Net income
$ 6,583
$ 6,471
$ 7,125
Company's equity in net income
$ 2,052
$ 2,022
$ 2,218
Included in Vermont Yankee's revenues shown above are sales to the Company of $59.1 million, $65.0 and $55.5 million for 1998 through 2000, 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 $8.8 million, $8.6 million and $9.8 million for 1998 through 2000, 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 continued in full force and effect until May 1995 and was extended for an additional two-year term in May 1995, and every two years thereafter, unless at least ninety (90) days prior to any two-year anniversary, any party were to 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.
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In March 2000, the phase angle regulator ("PAR"), which controls power flows over the transmission line between Plattsburgh, New York, and Milton, Vermont, failed due to internal core damage. Limited operations were restored within a week but without the PAR. The PAR, which is owned by the New York Power Authority has been repaired and was placed back in-service in February 2001.
To compensate for the loss of PAR control, VELCO operated the affected transmission line with limited inductor restriction and an increase of reactive power during high load periods. Consequently, VELCO installed one synchronous condenser near the Vermont terminus of this line to provide instantaneous support. The total costs of the facilities VELCO installed were spread among all electric customers in New England.
VELCO is also in the process of installing a Flexible Alternating Current Transmission System ("FACTS") device that will dynamically provide reactive support for the VELCO system. The FACTS device is on schedule to be in service May 1, 2001.
Summarized financial information for VELCO is as follows (dollars in thousands):
Earnings
Transmission revenues
$18,755
$16,935
$17,268
Operating income
$ 2,684
$ 2,633
$ 2,691
Net income
$ 1,257
$ 1,221
$ 1,153
Company's equity in net income
$ 645
$ 638
$ 581
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Note 3
Non-utility investments
Catamount
The Company's wholly owned subsidiary, Catamount Energy Corporation, a subsidiary of Catamount Resources Corporation, invests through its wholly owned subsidiaries, in non-regulated, energy-related projects in Western Europe and North America. Catamount's earnings were $0.7 million, $2.1 million and $3.3 million for 2000, 1999 and 1998, respectively. Certain financial information for Catamount's investments is set forth in the table that follows (dollars in thousands):
In 1998, Catamount replaced its $8.0 million credit facility with a $25.0 million revolving credit/term loan facility maturing November 2006, which provides for up to $25.0 million in revolving credit loans and letters of credit of which $21.6 million was outstanding at December 31, 2000. This facility has a security interest in Catamount's assets. 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. Catamount has committed to a $2.1 million letter of credit as well as a security interest in its stock securing the payment of cost overruns at the project which is currently behind schedule. As of December 31, 2000, the Company owns 100% of the Gauley River Power project, however, because of regulatory requirements the Company must reduce its ownership to a non-controlling level in order to meet Qualifying Facility status following completion of the project, therefore this investment has not been consolidated in the accompanying financial statements as the Company's control is considered temporary.
SmartEnergy
SmartEnergy, also a subsidiary of Catamount Resources Corporation, invests in unregulated energy and service-related businesses, including its 27.9% fully diluted ownership interest in HSS, as of December 31, 2000. Overall, SmartEnergy incurred net losses of $2.3 million, $2.9 million and $1.5 million for 2000, 1999 and 1998, respectively.
HSS establishes a network of affiliate contractors who perform home maintenance, repair and improvements via membership. This investment is accounted for using the equity method. HSS began operations in 1999 and is subject to risks and challenges similar to a company in the early stage of development.
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HSS began a limited rollout through Sam's Club in the second quarter of 1999. After this successful test, a national rollout was commenced at the end of 1999. A nationwide rollout also commenced in 2000 with TruServ Corporation (True Value Hardware Stores). On March 14, 2000, HSS issued 3,500,000 shares of convertible preferred stock. The proceeds of approximately $32.0 million, net of transaction costs, will be used by HSS to finance the national rollout of HSS. On October 4, 2000, in a stock transaction, HSS acquired ServiceBeyond.Com, a Web-based home services management company serving the San Diego, Denver and Dallas markets. On January 3, 2001, HSS raised an additional $10.0 million through the issuance of additional convertible preferred stock. As a result, SmartEnergy's ownership interest changed from 27.9%, as of December 1, 2000, to 26.3%, on a fully diluted basis, as of January 3, 2001.
HSS' pre-tax loss for 2000 was $31.0 million, of which SmartEnergy's share is $3.7 million. As of December 31, 2000, SmartEnergy has a net investment of $1.9 million.
Note 4
Common Stock
Through a common stock repurchase program that was suspended in 1997, the Company purchased from time to time 362,447 shares of its common stock in open market transactions at an average price of $13.04 per share. These transactions, net of 84,579 shares sold in connection with the Company's stock option plans, are recorded as treasury stock, at average 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.
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Note 6
Stock Award Plans
Stock Option Plans
The Company has awarded stock options to key employees and non-employee directors under various option plans approved in 1988, 1993, 1997, 1998 and 2000 that authorized the granting of options with respect to 1,375,875 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 and the maximum term of an option may not exceed five and ten years for non-employee directors and key employees, respectively. Shares available for future grants under the 1997, 1998 and 2000 stock option plans were 377,840 at December 31, 2000. No additional grants may be given under the 1988 and 1993 plans. Option activity during the past three years was as follows:
Average
Option
Price
Stock
Options
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
Options exercised
10.9375
(2,250)
Options granted
10.5742
95,860
Options expired
18.0476
(24,750)
Options outstanding at December 31, 1999
14.5714
584,860
Options exercised
10.7840
(23,700)
Options granted
10.7626
100,550
Options expired
15.4596
(128,725)
Options outstanding at December 31, 2000
$13.8067
532,985
The price range of options outstanding at December 31, 2000 is $10.5625 to $24.3125. The weighted average remaining contractual life at December 31, 2000 is 6.96 years and the weighted average exercise price is $13.1116. Exercisable options at December 31, 2000 total 487,185 and the weighted average exercise price is $12.7808.
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The Company accounts for these plans under Accounting Principles Board Opinion No. 25, under which no compensation cost has been recognized. 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):
Net Income
As reported
Pro forma
$18,043
$17,959
$16,584
$16,518
$3,983
$3,930
Earnings per share
of common stock
As reported
Pro forma
$ 1.42
$ 1.41
$ 1.28
$ 1.27
$ .18
$ .17
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:
Volatility
.2872
.2982
.1861
Risk-free rate of return
6.50%
5.50%
6.25%
Dividend yield
7.32%
7.26%
6.57%
Expected life in years
5-10
5-10
5-10
Restricted Stock Plans
Annual Incentive Program
Restricted stock performance awards have been granted to certain executive officers for the Company's annual Management Incentive Plan, under the 1997 Restricted Stock Plan for Non-employee Directors and Key Employees ("Restricted Plan"), including dividends and voting rights. Restricted stock was granted to non-employee directors for 50% of their annual retainer.
Recipients are not required to provide consideration to the Company under the Restricted Plan, other than rendering service, and have the right to vote the shares and to receive dividends under the Restricted Plan.
In accordance with APB 25, compensation cost is recognized for Restricted Plan shares, over the applicable vesting period, for the fair value of the restricted stock awarded, which is its market value without restrictions at the date of grant. Because this type of plan is classified as a variable plan, interim estimates of compensation are required based on a combination of the then-fair market value of the stock as of the end of the reporting period and the extent or degree of compliance with the performance criteria.
A total of 17,475 Restricted Plan shares were issued at an average market value of $10.64 in 2000, 3,424 shares at an average market value of $11.67 in 1999 and 3,255 shares at an average market value of $10.75 in 1998. These awards are recorded at the market value on the date of grant. Initially, the total market value of the shares is treated as unearned compensation and is charged to expense over the respective vesting periods.
Restricted Plan stock expense was $74,395 for 2000, $39,968 for 1999 and $35,000 for 1998.
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Long-term Incentive Plan
Restricted performance shares have been awarded for the Company's three-year vesting, Long-Term Incentive Plan, for executive officers, under the 1999 and 2000 Performance Share Incentive Plans ("Performance Plans").
The restricted stock awards under the Performance Plans will vest only if the Company achieves certain financial goals over three-year performance cycles. Recipients are not required to provide consideration to the Company under the Performance Plans, other than rendering service.
Under APB No. 25, for Performance Plan shares, adjustments are made to expense for changes in market value, achievement of financial goals and changes in employment, prior to completion of the performance cycle.
Performance Plan stock compensation charged to expense was $200,712 for 2000, none for 1999 and 1998.
Note 7
Long-term debt and sinking fund requirements
Utility
On July 30, 1999, the Company sold $75.0 million aggregate principal amount of 8 1/8% Second Mortgage Bonds due 2004 at a price of 99.915%.
The Company and its subsidiaries' long-term debt contains financial and non-financial covenants. At December 31, 2000, the Company and its subsidiaries were in compliance with all debt covenants related to its various debt agreements.
Based on outstanding debt at December 31, 2000, the aggregate amount of long-term debt maturities and sinking fund requirements are $4.2 million, $7.2 million, $13.3 million, $77.4 million and $2.2 million for the years 2001 through 2005, respectively. Substantially all utility property and plant is subject to liens under the First and Second Mortgage Bonds.
Non-Utility
On November 12, 1998, Catamount replaced its $8.0 million credit facility with a $25.0 million revolving credit/term loan facility maturing November 2006, which provides for up to $25.0 million in revolving credit loans and letters of credit. The amount outstanding at December 31, 2000 was $21.6 million. This facility has a security interest in Catamount's assets. Currently, a $1.2 million letter of credit is outstanding to support certain of Catamount's 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. Catamount has committed to a $2.1 million letter of credit as well as a security interest in its stock, securing the payment of cost overruns at the project which is currently behind schedule.
SmartEnergy Water Heating Services, Inc. ("SEWHS"), a wholly owned subsidiary of SmartEnergy, has a secured seven-year term loan with Bank of New Hampshire with an outstanding balance of $1.3 million at December 31, 2000. The interest rate is fixed at 9.50% per annum.
Financial obligations of the Company's subsidiaries are non-recourse to the Company, although future default under an arrangement for indebtedness of Catamount Energy or SEWHS, if unremedied, would trigger default under the
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Company's debt arrangements. Specifically, defaults under subsidiaries' debt instruments or subsidiary insolvencies can cause a default under the Company's First Mortgage Bond Indenture, which would then cause cross-defaults to the Company's other debt arrangements. The Company will propose an amendment to its First Mortgage Bond Indenture which, if approved by the bondholders, would remove this potential risk of default caused by the Company's unregulated subsidiaries.
Note 8
Short-term debt
Utility
The Company had no short-term debt outstanding at December 31, 2000 or at December 31, 1999.
The Company had a $50.0 million revolving credit facility with a group of banks, which matured and was repaid in 1999. The Company has an aggregate of $16.9 million of letters of credit with termination dates that have been extended to May 31, 2001. These letters of credit are subject to first mortgage interest and the same collateral supporting the Company's first mortgage bonds. In addition, the Company had a $12.0 million accounts receivable facility which was repaid by the Company in November 1999.
Note 9
Financial instruments
The estimated fair values of the Company's financial instruments at December 31, 2000 and 1999 are as follows (dollars in thousands):
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 classified amounts transferred under its receivable purchase agreement as secured borrowings. The facility matured and was repaid on November 29, 1999.
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
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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 Company elected to change the measurement date of pension obligations and related plan assets from December 31 to September 30. This was not considered material enough to present in the Consolidated Statement of Income as a change in accounting principle.
The following table sets forth the funded status of the pension plan and amounts recognized in the Company's Consolidated Balance Sheet and Statement of Income (dollars in thousands):
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Net pension costs include the following components
Service cost
$ 1,901
$ 1,854
$ 1,681
Interest cost
4,614
4,035
4,198
Expected return on plan assets
(5,873)
(5,081)
(4,720)
Amortization of prior service cost
Recognized net actuarial gain
(550)
-
-
Amortization of transition asset
(146)
(146)
(146)
Supplemental adjustment for amortization of FAS 71
Regulatory asset (1994 VERP)
-
Supplemental adjustment for amortization of FAS 71
Regulatory asset (1997 VERP)
Supplemental adjustment for amortization of FAS 71
Regulatory asset (CVEC)
-
-
Net periodic pension cost
1,356
1,885
Less amount allocated to other accounts
Net pension costs expensed
$ 582
$ 1,249
$ 1,657
Assumptions used in calculating pension cost were as follows:
The Company sponsors a defined benefit postretirement medical plan that covers all employees who retire with 10 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 Company elected to change the measurement date of postretirement medical plan obligations and related plan assets from December 31 to September 30. This was not considered material enough to present in the Consolidated Statement of Income as a change in accounting principle.
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The following table sets forth the plan's funded status and amounts recognized in the Company's Consolidated Balance Sheet and Statement of Income in accordance with SFAS No. 106 (dollars in thousands):
Net postretirement benefit costs include the
following components
Service cost
$ 183
$ 214
$ 194
Interest cost
Expected return on plan assets
(100)
(87)
(160)
Recognized net actuarial loss
-
Amortization of transition obligation
Supplemental adjustment for amortization of FAS 71
regulatory asset (1994 VERP)
-
Supplemental adjustment for amortization of FAS 71
regulatory asset (1997 VERP)
Supplemental adjustment for amortization of FAS 71
regulatory asset (CVEC)
-
-
Net periodic benefit cost
1,831
1,862
1,777
Less amount allocated to other accounts
Net postretirement benefit costs expensed
$1,617
$1,691
$1,568
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Assumptions used in the per capita costs of the accumulated postretirement benefit obligation were as follows:
Health care costs remain at 6.0% for people under 65 years of age for 2001 and thereafter and remain at 5.5% for people over 65 years of age for 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 $733,000 and $(628,000), respectively, in the accumulated postretirement benefit obligation as of December 31, 2000 and an increase (decrease) of about $51,000 and $(43,000), respectively, in the aggregate of the service cost and interest cost components of net periodic postretirement benefit cost for 2000.
The Company provides postemployment benefits consisting of long-term disability benefits. The accumulated postemployment benefit obligation at December 31, 2000 and 1999 of $1.1 million and $0.8 million, respectively, is reflected in the accompanying Consolidated Balance Sheet as a liability and is offset by a corresponding regulatory asset of $0.2 million for 2000 and $0.3 million for 1999. 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 2000, 1999 and 1998, including insurance premiums, were $481,000, $281,000 and $118,000, respectively (pre-tax).
In the third quarter of 1997, the Company offered and recorded obligations related to a voluntary retirement and severance program to employees. The estimated benefit obligation for the retirement program as of December 31, 2000 is approximately $1.8 million. This amount consists of pension benefits and post-retirement medical benefits of $0.9 million and
$0.9 million, respectively. The estimated benefit obligation for the
severance program, which included termination pay as well as other costs, is about $0.1 million as of December 31, 2000. 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 $2.5 million at December 31, 2000 will be amortized through December 31, 2002.
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Note 12
Income taxes
The components of federal and state income tax expense are as follows (dollars in thousands):
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):
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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):
The Company received an accounting order from the PSB dated September 30, 1997, authorizing 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 realized in the future.
Note 13
Retail Rates
The Company recognizes that adequate and timely rate relief is necessary if it is to maintain its financial strength, particularly since Vermont regulatory rules do not allow for changes in purchased power and fuel costs to be automatically passed on to consumers through rate adjustment clauses. The Company intends to continue its practice of periodically reviewing costs and requesting rate increases when warranted.
Vermont Retail Rate Proceedings: 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.
In response to the Company's September 1997 rate increase filing, the PSB decided to appoint an independent investigator to examine the Company's decision to buy power from Hydro-Quebec. The Company made a filing with the PSB stating that the PSB as well as other parties should be barred from reviewing past decisions because the PSB already examined the Company's decision to buy power from Hydro-Quebec in a 1994 rate case in which the Company was penalized for "improvident power supply management." During February 1998, the DPS filed testimony in opposition to the Company's retail rate increase request. The DPS recommended that the PSB instead reduce the
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Company's then current retail rates by 2.5% or $5.7 million. The Company sought, and the PSB granted, permission to stay this rate case and to file an interlocutory appeal of the PSB's denial of the Company's motion to preclude a re-examination of the Company's Hydro-Quebec contract in 1991. The Company has argued its position before the Vermont Supreme Court.
On June 12, 1998, the Company filed with the PSB for a 10.7% retail rate increase that supplanted the September 22, 1997 rate increase request of 6.6%, to be effective March 1, 1999. On October 27, 1998, the Company reached an agreement with the DPS regarding the June 1998 retail rate increase request providing 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 on or after January 1, 1999. The agreement was approved by the PSB on December 11, 1998.
The 4.7% rate increase is subject to retroactive or prospective adjustment upon future resolution of issues arising under the Hydro-Quebec and the VJO Power Contract. The agreement temporarily disallows approximately $7.4 million (based on 1999 power costs) for the Company's purchased power costs under the VJO Power Contract. As a result of the 4.7% rate increase agreement, during the fourth quarters of 1998 and 1999, the Company recorded pre-tax losses of $7.4 million and $2.9 million, respectively, for disallowed purchased power costs, representing the Company's estimated under recovery of power costs, prior to further
resolution, under the VJO Power Contract for 1999 and the first quarter of
2000, respectively. In 2000, an additional $11.5 million pre-tax loss was recorded for the estimated under recovery of Hydro-Quebec power costs for the second, third and fourth quarters of 2000, and the first quarter of 2001. If in the future, the Company is unable to increase rates to recover the temporary disallowed purchased power costs prior to further resolution under the VJO Power Contract or otherwise mitigate these costs, the Company would be required to record losses for any estimated future under recovery.
These temporary disallowances were calculated using comparable methodology to that used by the PSB in the GMP rate case on February 28, 1998. In that case, the PSB found GMP's decision to commit to the VJO Power Contract in 1991 "imprudent" and that power purchased under it was not "used and useful." As a result, the PSB concluded that a portion of GMP's current costs should not be imposed on GMP's customers and were disallowed. GMP appealed that rate order to the Vermont Supreme Court. Should the Company receive a similar order from the PSB, the Company would experience a material adverse effect on its results of operations and financial condition.
In January 2001, the PSB issued an order that restored financial stability to GMP through a 3.42% rate increase over and above the two temporary rate increases that were already in effect for that company. In addition to those conditions agreed to by GMP and the DPS, the PSB has required GMP to return up to $8.0 million to ratepayers in the event of a merger, acquisition or asset sale, and also placed restrictions on GMP's investments in non-regulated operations. In addition, GMP agreed to withdraw its Vermont Supreme Court appeal regarding the VJO contracts described above.
On February 9, 2001, the Vermont Supreme Court issued a decision on the Company's 1998 rate case appeal that reversed the PSB's decision on the preclusion issues and remanded the case to the PSB for further proceedings consistent with the Vermont Supreme Court's decision. However, if the PSB subsequently issues a final rate order adopting the disallowance methodology
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used to determine the temporary Hydro-Quebec disallowance described above for the duration of the VJO Power Contract, the Company would not be able to recover approximately $179.7 million of power costs over the life of the
contract, including $11.3 million in 2001, $11.4 million in 2002, $11.5
million in 2003, $11.7 in million 2004 and $11.8 million in 2005. In such an event, the Company would be required to take an immediate charge to earnings of approximately $179.7 million (pre-tax). Such an outcome could jeopardize the Company's ability to continue as a going concern. However, at this time, the Company does not believe that such a loss is probable particularly in view of the January, 2001 PSB Order issued in GMP's proceedings, and the decision of the Vermont Supreme Court reversing and remanding the PSB's order.
On April 13, 2000, the Company and the DPS filed a stipulated agreement with the PSB to end winter-summer rate differentials for the Company's Vermont customers. On June 8, 2000, the PSB approved the Company's request to end the winter-summer rate differential and, therefore, the Company now has flat rates throughout a given year. Winter rates have been reduced by 14.9%, while summer rates have been increased by 10.5%. The rate design change will be revenue neutral over a 12-month period. The additional 2000 revenues, resulting from implementing this change in mid-year, have been applied to reduce or eliminate certain regulatory deferrals, as ordered by the PSB.
In an effort to mitigate eroding earnings and cash flow prospects in the future, due mainly to under recovery of power costs, on November 9, 2000, the Company filed with the PSB a request for a 7.6% rate increase ($19.0 million of annualized revenues) effective July 1, 2001.
The PSB suspended the rate filing and a schedule has been set to review the case. An order from the PSB is expected by July 24, 2001. The Company is engaged in settlement discussions with the DPS in an effort to settle the 2000 retail rate case. The Company cannot predict the outcome of those settlement discussions or the ultimate outcome of this rate case.
New Hampshire Retail Rate/Federal Court Proceedings
Connecticut Valley's retail rate tariffs, approved by the 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 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
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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 November 26, 1997, Connecticut Valley filed a request with the NHPUC to increase FAC, PPCA and short-term energy purchase rates effective on 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 over collections 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.
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 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 Statement of Financial Accounting Standards No. 71 ("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 in 1997 for disallowed power costs.
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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 Order. 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 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 PSNH and the other utilities that had been allowed to intervene in these proceedings, including the Company and Connecticut Valley. The plaintiffs-interveners 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 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
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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 Court of Appeals.
On July 23, 1998, the NHPUC issued an order vacating that portion of its February 27, 1997 restructuring order that had directed Connecticut Valley to terminate its RS-2 wholesale power purchases from the Company. The NHPUC has expressly stated in federal court filings that its July 23, 1998 order "clarified that Connecticut Valley should not terminate the RS-2 Rate Schedule if such termination would trigger the exit fee" for which the Company has sought authorization from FERC.
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 implement the proposed FAC and PPCA rates, 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 Federal District Court Order, should it be overturned or modified, which are included in the estimated total losses of $4.3 million discussed below.
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 arguments as strong 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 also 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.
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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 the NHPUC ordered Connecticut Valley's rates to be reduced below the level existing as of December 31, 1997, "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 could file a petition of certiorari to the United States Supreme Court and the Supreme Court acted 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 April 19, 1999 the Supreme Court denied the petition for certiorari.
As a result of the December 3, 1998 Court of Appeals' decision discussed 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 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 estimated 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, and implemented the refund effective April 1, 1999.
As a result of legal and regulatory actions discussed above, Connecticut Valley no longer qualified as of December 31, 1998 for the application of SFAS No. 71, and wrote-off in the fourth quarter of 1998 all of its regulatory assets associated with its New Hampshire retail business estimated at approximately $1.3 million on a pre-tax basis at December 31, 1998. In addition, Connecticut Valley also recorded estimated total losses of $4.3 million pre-tax during the fourth quarter of 1998 for disallowed power costs of $1.6 million and its refund obligations of $2.7 million.
The pre-tax losses described above resulted in Connecticut Valley violating applicable covenants, which if not waived or renegotiated, would have allowed Connecticut Valley's lender the right to accelerate the repayment of a $3.75 million loan with Connecticut Valley. On March 12, 1999, Connecticut Valley was notified by the Bank that it would exercise
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appropriate remedies in connection with the violation of financial covenants associated with the $3.75 million loan agreement unless the violation was cured by April 11, 1999. To avoid default of this loan agreement, on April 6, 1999, pursuant to an agreement reached on March 26, 1999, the Company purchased from the Bank the $3.75 million note.
On April 7, 1999, the Court ruled from the bench that the March 22, 1999 NHPUC Order requiring Connecticut Valley to provide a refund to its retail customers was illegal and beyond the NHPUC's authority. The Court also ruled that the NHPUC cannot reduce Connecticut Valley's rates below rates in effect at December 31, 1997. Accordingly, Connecticut Valley removed the rate refund from retail rates effective April 16, 1999. Lastly, the Court denied the NHPUC's motion to dissolve the injunction staying the implementation of its restructuring plan and stated its desire to rule on the pending motion for summary judgement and to conduct a hearing on the Company's request for a permanent injunction, after the NHPUC completes hearings on PSNH's stranded costs. The District Court's decision was issued as a written order on May 11, 1999.
The NHPUC held a hearing on April 22, 1999 to determine whether to modify Connecticut Valley's 1999 power rates by returning the rates to the levels that were in effect on December 31, 1997. On May 17, 1999, the NHPUC issued an order requiring Connecticut Valley to set temporary rates at the level in effect as of December 31, 1997, subject to future reconciliation, effective with bills issued on and after June 1, 1999.
On May 24, 1999, the NHPUC filed a petition for mandamus in the Court of Appeals challenging the Court's May 11, 1999 ruling and seeking a decision allowing the refunds as required by the NHPUC's March 22, 1999 Order. The Court of Appeals denied that petition on June 2, 1999. The NHPUC immediately filed a notice of appeal in the Court of Appeals again challenging the Court's May 11, 1999 ruling. In that appeal, the Company and Connecticut Valley contend, among other things, that it is unfair for the NHPUC to direct Connecticut Valley to continue to purchase wholesale power under RS-2 in order to avoid the triggering of a FERC exit fee, but at the same time to freeze Connecticut Valley's rates at their December 31, 1997 level which does not enable Connecticut Valley to recover all of its RS-2 costs.
On June 14, 1999, PSNH and various parties in New Hampshire announced that a "Memorandum of Understanding" had been reached that is intended to result in a detailed settlement proposal to the NHPUC that would resolve PSNH's claims against the NHPUC's restructuring plan. On July 6, 1999, PSNH petitioned the Court to stay its proceedings indefinitely while the proposed settlement is reviewed and approved by the NHPUC and the New Hampshire Legislature. On July 12, 1999, the Company and Connecticut Valley objected to any stay that would allow the NHPUC's rate freeze order to remain in effect for an extended period and asked the Court to proceed with prompt hearings on its summary judgement motion and trial on the merits. On October 20, 1999 the Court heard oral arguments pertaining to the pretrial motions of the Company and the NHPUC for summary judgement and dismissal, respectively.
On December 1, 1999, Connecticut Valley filed with the NHPUC a petition for a change in its FAC and PPCA rates effective on bills rendered on and after January 1, 2000. On December 30, 1999, the NHPUC denied Connecticut Valley's request to increase its FAC and PPCA rates above those in effect at December 31, 1997, subject to further investigation and reconciliation until otherwise ordered by the NHPUC. Accordingly, during the fourth quarter of 1999 Connecticut Valley recorded a pre-tax loss of $1.2 million for under collection of year 2000 power costs.
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The Court of Appeals issued a decision on January 24, 2000, which upheld the Court's preliminary injunction enjoining the Commission's restructuring plan. The decision also remanded the refund issue to the Court stating:
"the district court may defer vacation of this injunction against the refund order for up to 90 days. If within that period it has decided the merits of the request for a permanent injunction in a way inconsistent with refunds, or has taken any other action that provides a showing that the Company is likely to prevail on the merits in federal court in barring the refunds, it may enter a superseding injunction against the refund order, which the Commission may then appeal to us. Otherwise, no later than the end of the 90-day period, the district court must vacate its present injunction insofar as it enjoins the Commission's refund order."
On March 6, 2000, the Court granted summary judgement to Connecticut Valley and the Company on their claim under the filed-rate doctrine and issued a permanent injunction mandating that the NHPUC allow Connecticut Valley to pass through to its retail customers its wholesale costs incurred under the RS-2 rate schedule with the Company. The Court also ruled that Connecticut Valley is entitled to recover those wholesale costs that the NHPUC has disallowed in retail rates since January 1, 1997. This decision was appealed by the NHPUC to the Court of Appeals. The NHPUC also requested the Court of Appeals to stay the Court's order pending the Court's review on appeal. In response, Connecticut Valley offered to place the additional revenues in escrow pending the outcome of appeal. The Court of Appeals denied the NHPUC's request for a stay so long as the incremental revenues were placed in escrow.
Pursuant to the March 6, 2000 Court's Order, on March 17, 2000 Connecticut Valley filed a rate request with the NHPUC for an Interim FAC/PPCA to recover the balance of wholesale costs not recovered since January 1997. To mitigate the rate increase percentage, the Interim FAC/PPCA were designed to recover current power costs and a substantial portion of past under collections by the end of 2000; the remainder of the past under collections will be collected during 2001 along with 2001 power costs. The
NHPUC held a hearing on April 7, 2000 to review the 12.3% increase that would raise $1.6 million of revenues in 2000. The NHPUC issued an order approving the rates as temporary effective May 1, 2000.
On July 25, 2000, the Court of Appeals affirmed the Court's March 6, 2000 Order granting summary judgement to Connecticut Valley and the Company. The NHPUC then asked the Court of Appeals to reconsider its decision. That request was denied. As a result of the favorable Court of Appeals action, Connecticut Valley recorded a $2.0 million after-tax gain in the third quarter of 2000. On November 27, 2000, the NHPUC filed a petition for writ of certiorari with the United States Supreme Court. On February 20, 2001 the Supreme Court denied the petition for certiorari, thus leaving the Court of Appeals approval of the permanent injunction intact.
FERC Proceedings
The Company filed an application with the FERC in June 1997 to recover stranded costs in connection with its wholesale rate schedule with Connecticut Valley and a notice of cancellation of the Connecticut Valley rate schedule (contingent upon the recovery of the stranded costs that would result from the cancellation of this rate schedule). In December 1997, the FERC rejected the Company's proposal to recover stranded costs through the imposition of a surcharge on our transmission tariff, but indicated that it would consider an exit fee mechanism for collecting stranded costs. The FERC
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denied the Company's motion for a rehearing regarding the surcharge proposal, so the Company filed a request with the FERC for an exit fee mechanism to collect the stranded costs resulting from the cancellation of the contract with Connecticut Valley. The stranded cost obligation sought to be recovered through an exit fee, expressed on a net present value basis as of December 31, 2000, is approximately $41.5 million. 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. During April and May 1999, nine days of hearings were held at the FERC before an Administrative Law Judge, who will determine, among other things, whether Connecticut Valley qualifies for an exit fee, and if so, the amount of Connecticut Valley's stranded cost obligation to be paid to the Company as an exit fee. The ruling of the Administrative Law Judge could be issued at any time. Thereafter the FERC will act on the judge's recommendations.
If the Company is unable to obtain an order authorizing the recovery of costs in connection with the June 1997 FERC filing or in the Federal Court, it is possible that the Company would be required to recognize a pre-tax loss under this contract totaling approximately $47.1 million as of December 31, 2000. The Company would also be required to write-off approximately $1.5 million (pre-tax) in regulatory assets associated with its wholesale business as of December 31, 2000. If the Company obtains a FERC order authorizing the requested exit fee, Connecticut Valley will have to apply to the NHPUC to increase rates in order to pay the exit fee. The Company believes that the NHPUC must permit Connecticut Valley to raise its rates to recover the cost of the exit fee. However, if Connecticut Valley is unable to recover its costs by increasing its rates, Connecticut Valley would be required to recognize the loss described above.
In addition to its efforts before the Court and FERC, Connecticut Valley has initiated efforts and will continue to work for a negotiated settlement with parties to the New Hampshire restructuring proceeding and the NHPUC.
An adverse resolution of these proceedings would have a material adverse effect on the Company's results of operations and cash flows. However, the Company cannot predict the ultimate outcome of this matter.
Wheelabrator Power Contract
Connecticut Valley purchases power from several Independent Power Producers ("IPP's"), who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. In 2000, under long-term contracts with these qualifying facilities, Connecticut Valley purchased 39,998 mWh, of which 37,603 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 for 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 denied the Company's appeal, but indicated that the Company could seek relief from the NHPUC. On May 12, 2000, the company filed a petition with the NHPUC seeking (1) to amend the contract to permit purchase of net, rather than gross, output of the plant and (2) a refund, with interest, of past purchases of the difference between net and gross output.
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In December 2000 and January 2001, Wheelabrator, the New Hampshire/Vermont Solid Waste District, and several Connecticut Valley
residential customers filed with the NHPUC to intervene. The Office of
Consumer Advocate and the NHPUC Staff are automatic parties. A Prehearing Conference was held before the NHPUC on January 4, 2001, at which time each party provided preliminary position statements with regard to the petition. The Company cannot predict the outcome of this matter.
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 nuclear generating plant. On July 27, 2000 the company executed a settlement agreement with NU resolving all issues related to arbitration and lawsuits sought to recover costs associated with the shutdown of Unit #3 in 1996, due to operational and management deficiencies. The cash settlement of $5.4 million was received in August 2000, and is reflected as other income in the Consolidated Statement of Income. On September 15, 1999, NU announced its intent to auction its nuclear generating plants, including Unit #3. On August 7, 2000, the Connecticut Department of Public Utility Control announced that Dominion Resources, Inc.
was the successful bidder in the auction. Pursuant to the terms of the settlement agreement with NU that resolved the Company's claims against NU relating to the extended outage of Unit #3, the Company participated as a potential seller in that auction. Upon notification of the sales price, the Company evaluated and declined the purchase offer.
The Company purchases power from a number of IPPs who own qualifying facilities under the Public Utility Regulatory Policies Act of 1978. These qualifying facilities produce energy using hydroelectric, biomass and refuse-burning generation. The majority of these purchases are made from a state appointed purchasing agent who purchases and redistributes the power to all Vermont utilities. Under these long-term contracts, in 2000, the Company received 200,919 mWh of which 144,310 mWh is associated with the Vermont Electric Power Producers and 37,603 mWh with the New Hampshire/Vermont Solid Waste Plant owned by Wheelabrator Claremont Company, L.P. The Company expects to purchase approximately 200,000 mWh of independent power output in each year 2001 through 2005. Based on the forecast level of production, the total commitment in the next five years to purchase power from these independent power facilities is estimated to be $118 million.
The Company is purchasing varying amounts of power from Hydro-Quebec under the VJO contract through 2016. 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.
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The average annual amount of capacity that the Company will purchase from January 1, 2001 through October 31, 2016 is 131 mW. The total commitment to purchase power under these contracts on a nominal basis is approximately $937 million net of power sellbacks over the contract term. In February 1996, the Company reached an agreement with Hydro-Quebec that
lowered the 1997 cost of power by $5.8 million. As part of this agreement, the Company makes 54 mW of Phase I/II capacity available to Hydro-Quebec for its use to deliver an existing Firm Energy Contract or jointly marketed energy contracts to buyers in NEPOOL during the period from 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 received 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 upon four year's written notice, to reduce capacity deliveries by up to 50 mW beginning as early as 2004 until 2015. This option includes the use of a like amount of the Company's Phase I/II facility rights. Hydro Quebec also can exercise an option, upon one year's written notice, to curtail energy deliveries from an annual load factor of 75% to 50% due to adverse hydraulic conditions in Quebec. This can be exercised five times between November 2000 and October 2015.
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, 2000 the Company's VJO obligation is approximately 43% or $937 million 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 contract is approximately $2.2 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 Power Contract with Hydro-Quebec. This resulted in a 61-day interruption of a significant portion of scheduled contractual energy 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. On the basis of that examination, the VJO determined that Hydro-Quebec has been and remains unable to make available capacity with the degree of firmness required by the VJO Power Contract. That determination prompted the VJO to initiate an arbitration proceeding. In the arbitration, the VJO is seeking to terminate the contract, to recover damages associated with Hydro-Quebec's failure to comply with the contract, and to recover capacity payments made during the period of non-delivery.
In September 1999 an initial two weeks of hearings were held dealing primarily with issues of contract interpretation. Additional hearings dealing with technical issues were held in the second and third quarters of 2000. The Company expects a decision in the first half of 2001. In accordance with a PSB Accounting Order, the Company has deferred incremental costs associated with this arbitration of approximately $6.3 million. These deferred costs have been offset by incremental revenue of $3.8 million,
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resulting from the implementation of deseasonalized rates on July 1, 2000, as directed by the PSB. Recovery of these net costs will be determined in the pending rate proceedings.
Joint-ownership The Company's ownership interests in jointly owned generating and transmission facilities are set forth in the following table that follows and recorded in the Company's Consolidated Balance Sheet (dollars in thousands.)
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.
VELCO is currently in the process of upgrading its transmission facilities in the Burlington, Vermont area where the Joseph C. McNeil generating plant is located. These transmission improvements may reduce the current need for the Joseph C. McNeil generating plant to run in support of area reliability and are expected to be in place in the second half of 2001. The Company anticipates that upon completion of the upgrade, the Joseph C. McNeil generating plant may not operate at its current capacity factor.
The Company is responsible for paying its ownership percentage of decommissioning costs for Millstone Unit #3. Based on a 1997 study, the total estimated obligation at December 31, 2000 was approximately $580.9 million and the funded obligation was about $247.5 million. The Company's share for the total obligation and funded obligation was approximately $10.7 million and $4.2 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
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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 four different locations. The Company discontinued these activities 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 past 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.
Cleveland Avenue Property The Company's Cleveland Avenue property, located in the City of Rutland, Vermont, was 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 has continued
over the last several years and the Company continues to work with the State of Vermont in a joint effort to develop a mutually acceptable solution.
Brattleboro Manufactured Gas Facility From the early to late 1940's, the Company owned and operated a manufactured gas facility in Brattleboro, Vermont ("VT"). The Company received a letter from the State of New Hampshire ("NH") asking the Company to conduct a scoping study in and around the site of the former facility. The Company commissioned an environmental site assessment in late 1999. In April 2000, the Company presented the assessment findings to the states of NH and VT and the town of Brattleboro. The State of VT concluded that additional site monitoring is necessary and the Company submitted a draft Corrective Action Plan that includes a long-term groundwater monitoring program and implements institutional controls at the site to restrict access and exposure. The Company expects to receive State of VT approval of the draft Corrective Action Plan in early 2001 and will implement the plan thereafter. The State of NH concluded that additional biological monitoring of the river sediment affected by site wastes is necessary. The State of NH requires this additional work to validate certain findings and conclusions made by the Company's consultant after completing its initial investigation in 1999. The Company will also
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develop and submit a work plan to the State of NH in early 2001 to address their concerns. The Company expects state approval so it can complete the work and report on the findings in 2001. At this time the Company has not finalized an estimate of its potential liability at this site.
Dover, New Hampshire, Manufactured Gas Facility In late 1999, the Company was contacted by Public Service Company of New Hampshire ("PSNH") with respect to this site. PSNH alleges the Company is partially liable for remediation of this site. PSNH's allegation is premised on the fact that
prior to PSNH's purchase of the facility, it was operated by Twin State Gas and Electric ("Twin State"). Twin State merged with the Company on the same day the facility was sold to PSNH. The Company researched the underlying transactions and the transactions appeared vague and complex regarding environmental liability. In view of this, the Company proposed, and PSNH accepted, an agreement that calls for an environmental mediator to assist in a non-binding evaluation of the Company's liability. The Company along with PSNH and EnergyNorth Natural Gas, Inc. will start this mediation process in the first quarter of 2001. In December 2000, PSNH submitted a work plan to the State of NH for further investigation of this site. The Company agreed, with reservations, to participate in the development and completion of that work since the State of NH considers the Company, along with others, as potentially responsible parties at the site. This work requires state review, comment and approval and will occur in 2001. At this time, the Company has not finalized an estimate of its potential liability at this site.
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 any other federal or state agency sought contribution from the Company for the study or remediation of any such sites.
As of December 31, 2000, a reserve of $9.5 million has been established representing management's best estimate of the costs to remediate the sites discussed above.
Dividend restrictions The indentures relating to long-term debt, the Articles of Association and a covenant contained in the Reimbursement Agreements to the letters of credit, supporting the Company's tax exempt revenue bonds, contain certain restrictions on the payment of cash dividends on capital stock. Under the most restrictive of such provisions, approximately $98.3 million of retained earnings was not subject to dividend restriction at December 31, 2000.
Under the Company's Second Mortgage Indenture, certain additional restrictions on the payment of dividends would become effective if the Company's Second Mortgage Bonds are rated below investment grade. Under the most restrictive of these provisions, approximately $18.9 million of retained earnings would not be subject to dividend restrictions at December 31, 2000.
In addition, Catamount and SmartEnergy Water Heating Services, Inc., have debt instruments in place that restrict the amount of dividends on capital stock that they are able to pay.
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
Page 97 of 129
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 expected payments
will range and decline from approximately $4.0 million to $3.0 million for each year from 2001 through 2015 and will decline thereafter. The Company's shares of the net capital cost of these facilities, totaling approximately $15.1 million, are classified in the accompanying Consolidated Balance Sheet as "Utility Plant" and "Capital lease obligations" (current and non-current).
Minimum rental commitments of the Company under non-cancelable leases as of December 31, 2000, are considered minimal as the majority of the Company's leases are cancelable after one year from lease inception. Total rental expense entering into the determination of net income, consisting principally of vehicle and equipment rentals, was approximately $4.0 million for 1998, $4.2 million for 1999 and $4.2 million for 2000.
Legal proceedings On August 7, 1997, the Company and eight other non-operating owners of Millstone Unit #3 filed a demand for arbitration with Connecticut Light and Power Company and Western Massachusetts Electric Company, both NU affiliates, and lawsuits against NU and its trustees. The arbitration and lawsuits sought to recover costs associated with replacement power, operation and maintenance costs and other costs resulting from the shutdown of Millstone 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. A settlement was reached on July 27, 2000. The settlement became effective August 4, 2000, and provided for a cash payment of $5,445,000 which was booked as other income on the Consolidated Statement of Income.
On September 15, 1999, NU announced that it intends to auction its nuclear generating plants, including Unit #3. On August 7, 2000, the Connecticut Department of Public Utility Control announced that Dominion Resources, Inc. was the successful bidder in the auction. The sale is expected to become final in April 2001. Pursuant to the terms of the settlement agreement with NU which resolved the Company's claims against NU relating to the extended 1996 outage of Unit #3, the Company participated as a potential seller in that auction. Upon notification of the sales price, the Company evaluated and declined the purchase offer.
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.
Change of control The Company has management continuity agreements with certain Officers which become operative upon a change in control of the Company. Potential severance expense under the agreements varies over time depending on several factors, including the specific plan for individual officers and officers' compensation and age at the time of the change of control.
Page 98 of 129
Note 15
Recent Accounting Pronouncements
In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. In June 1999, the FASB issued SFAS No. 137, Accounting for Derivative Instruments and Hedging Activities -- Deferral of the Effective Date of SFAS No. 133 and in June 2000, issued SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Activities, an amendment to SFAS No. 133. This Statement, SFAS No. 133 as amended, 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. The 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, as amended, is effective for fiscal years beginning after June 15, 2000. A company may also implement SFAS No. 133 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. With respect to hybrid instruments, a company may elect to apply SFAS No. 133, as amended, to (1) all hybrid contracts, (2) only those hybrid instruments that were issued, acquired or substantively modified after December 31, 1997 or (3) only those hybrid instruments that were issued, acquired or substantively modified after December 31, 1998.
The Company completed its review and implementation of SFAS No. 133, effective January 1, 2001. The Company has taken an inventory of its contracts and determined that two of the contracts are derivatives under SFAS No. 133. One contract is a long-term purchased power contract that allows
the seller to purchase specified amounts of power with advance notice. Based on the application of rate regulated accounting principles, this contract is not expected to have a material impact on stockholders' equity or net income. The second contract is an interest rate swap that qualifies for hedge accounting under SFAS No. 133 and is not expected to have a material impact on stockholders' equity.
Page 99 of 129
Note 16
Segment Reporting	
In 1998, the Company adopted SFAS No.131,"Disclosures about Segments of an Enterprise and Related Information," which establishes standards for reporting operating segments and related disclosures. 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, 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 ("CV") which engages in the purchase, production, transmission, distribution and sale of electricity in Vermont; Connecticut Valley Electric Company Inc. ("CVEC") which distributes and sells electricity in parts of New Hampshire; Catamount which invests in non-regulated, energy-supply projects and SmartEnergy which pursues retail alliances to market energy and related products and services, engages in the sale of or rental of electric water heaters and has a 27.9% ownership interest in HSS, on a fully diluted basis, as of December 31, 2000. CVEC, while managed on an integrated basis with CV, is presented separately because of its separate and distinct regulatory jurisdiction. Other operating segments include a segment below
the quantitative threshold for separate disclosure. This operating segment
is 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. Segment information for 1998 has been restated to separately present SmartEnergy which became a reportable segment in 1999.
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 CVEC and revenues for support services to CVEC, 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.
Page 100 of 129
Financial Information by industry segment for the three years ended December 31, 2000, is as follows (dollars in thousands):
Includes a segment below the quantitative threshold.
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.
Included in Purchased power in the accompanying Consolidated Statement of Income.
See Note 2 herein for CV's investments in affiliates.
Page 101 of 129
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):
Item 9.
Item 9. Changes in and Disagreements with
Accountants on Accounting and Financial Disclosure.
None.
PART III
Item 10.
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" and Section 16(a) Beneficial Ownership Reporting Compliance in the Proxy Statement for the 2001 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 or about March 26, 2001.
Item 11.
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 2001 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 or about March 26, 2001.
Item 12.
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 2001 Annual
Page 102 of 129
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 or about March 26, 2000.
Item 13.
Item 13. Certain Relationships and Related Transactions.
None
PART IV
Filed
Herewith
at Page
Item 14.
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, 2000
Consolidated Statement of Cash Flows, for each of the three
years ended December 31, 2000
Consolidated Balance Sheet at December 31, 2000 and 1999
Consolidated Statement of Capitalization at
December 31, 2000 and 1999
Consolidated Statement of Changes in Common Stock Equity
for each of the three years ended December 31, 2000
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, 2000
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.
Page 103 of 129
(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)
Page 104 of 129
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)
Page 105 of 129
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)
Page 106 of 129
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, 1997 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 (Exhibit 4-56.3, 1998 Form 10-K,
File No. 1-8222)
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 (Exhibit 4-56.4, 1998 Form 10-K, File No.
1-8222)
Fourth Amendment to Credit Agreement, dated as of
May 25, 1999 (Exhibit 4-56.4, Form 10-Q,
June 30, 1999, File No. 1-8222)
4-56.5 Security Agreement, dated as of October 5, 1998,
between the Company and Toronto Dominion (Texas),
Inc. (Exhibit 4-56.5, 1998 Form 10-K, File No.
1-8222)
Page 107 of 129
4-57 Forty-First Supplemental Indenture, dated as of July 19, 1999
and resolutions establishing Series PP (Millstone) Bonds,
Series QQ (Seabrook) Bonds and Series RR (East Barnet) Bonds
And matters connected therewith adopted July 19, 1999
(Exhibit 4-57, Form 10-Q, September 30, 1999, File No. 1-8222)
4-58 Second Mortgage Indenture, dated as of July 15, 1999, Central
Vermont Public Service Corporation to the Bank of New York,
Trustee (Exhibit 4-58, Form 10-Q, September 30, 1999,
File No. 1-8222)
4-59 First Supplemental Indenture to the Second Mortgage, Central
Vermont Public Service Corporation to the Bank of New York,
Trustee, dated as of July 15, 1999, creating an issue of
Mortgage Bonds, 8-1/8% Second Mortgage Bonds due 2004
(Exhibit 4-59, Form 10-Q, September 30, 1999, File No. 1-8222)
4-60 A/B Exchange Registration Rights Agreement, dated as of
July 30, 1999 by and among Central Vermont Public Service
Corporation and Donaldson, Lufkin & Jenrette Securities
Corporation, TD Securities (USA) Inc. (Exhibit 4-60, Form
10-Q, September 30, 1999, File No. 1-8222)
Exhibit 10 Material Contracts (*Denotes filed herewith)
Incorporated herein by reference:
10.l Copy of firm power Contract dated August 29, 1958, and
supplements thereto dated September 19, 1958,
October 7, 1958, and October 1, 1960, between the Company
and the State of Vermont (the "State"). (Exhibit C-1,
File No. 2-17184)
10.1.1 Agreement setting out Supplemental NEPOOL
Understandings dated as of April 2, 1973.
(Exhibit C-22, File No. 5-50198)
10.2 Copy of Transmission Contract dated June 13, 1957, between
Velco and the State, relating to transmission of power.
(Exhibit 10.2, 1993 Form 10-K, File No. 1-8222)
10.2.1 Copy of letter agreement dated August 4, 1961,
between Velco and the State. (Exhibit C-3, File No. 2-26485)
10.2.2 Amendment dated September 23, 1969. (Exhibit C-4,
File No. 2-38161)
10.2.3 Amendment dated March 12, 1980. (Exhibit C-92,
1982 Form 10-K, File No. 1-8222)
10.2.4 Amendment dated September 24, 1980. (Exhibit C-93,
1982 Form 10-K, File No. 1-8222)
10.3 Copy of subtransmission contract dated August 29, 1958,
between Velco and the Company (there are seven similar
contracts between Velco and other utilities). (Exhibit 10.3,
1993 Form 10-K, Form No. 1-8222)
10.3.1 Copies of Amendments dated September 7, 196l,
November 2, 1967, March 22, 1968, and
October 29, 1968. (Exhibit C-6, File No. 2-32917)
Page 108 of 129
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)
Page 109 of 129
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)
10.8.8 Amendment No. 8 dated November 17, 1999. (Exhibit
10.8.8, Form 10-Q, June 30, 2000, File No. 1-8222)
10.8.9 Amendment No. 9 dated November 17, 1999. (Exhibit
10.8.9, Form 10-Q, June 30, 2000, 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)
Page 110 of 129
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)
Page 111 of 129
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)
Page 112 of 129
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)
Page 113 of 129
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)
Page 114 of 129
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)
Page 115 of 129
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)
10.27.6 1987 Supplementary Power Contract, dated as of
April 1, 1987. (Exhibit 10.27.6, Form 10-Q,
June 30, 2000, File No. 1-8222)
10.27.7 1996 Amendatory Agreement, dated December 1, 1996.
(Exhibit 10.27.7, Form 10-Q, June 30, 2000,
File No. 1-8222)
10.27.8 2000 Amendatory Agreement, dated May, 2000.
(Exhibit 10.27.8, Form 10-Q, June 30, 2000,
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)
Page 116 of 129
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)
Page 117 of 129
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)
Page 118 of 129
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)
Page 119 of 129
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)
Page 120 of 129
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.
Page 121 of 129
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)
Page 122 of 129
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
(Exhibit 10.84, 1998 Form 10-K, File No. 1-8222)
A 10.85 Officers' Supplemental Retirement and Deferred Compensation
Plan as Amended and Restated Effective January 1, 1998
(Exhibit 10.85, 1998 Form 10-K, File No. 1-8222)
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 10.89 Management Incentive Plan for Executive Officers dated
January 1, 1999. (Exhibit A10.89, Form 10-Q, March 31, 1999,
File No. 1-8222)
A 10.90 Performance Share Incentive Plan dated effective
January 1, 1999. (Exhibit A10.90, Form 10-Q, June 30, 1999,
File No. 1-8222)
A 10.91 Management Incentive Plan for Executive Officers dated
January 1, 2000. (Exhibit A10.91, Form 10-Q, March 31, 2000,
File No. 1-8222)
A 10.92 Officers' Change of Control Agreements as approved
April 3, 2000. (Exhibit A10.92, Form 10-Q, March 31, 2000,
File No. 1-8222)
A - Compensation related plan, contract, or arrangement.
21. Subsidiaries of the Registrant
* 21.1 List of Subsidiaries of Registrant
23. Consents of Experts and Counsel
* 23.1 Consent of Independent Public Accountants
24. Power of Attorney
* 24.1 Powers of Attorney executed by Directors and Officers of Company
Page 123 of 129
27. Reports on Form 8-K:
The Company filed the following reports on Form 8-K during the
quarter ended December 31, 2000:
1. Item 5. Other Events, dated November 16, 2000 re: Sale of Vermont
Yankee Nuclear Power Corporation.
Page 124 of 129
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Central Vermont Public Service Corporation:
We have audited in accordance with auditing standards generally accepted in the United States, the consolidated financial statements included in Central Vermont Public Service Corporation's annual report to shareholders, included in this Form 10-K, and have issued our report thereon dated February 5, 2001 (except with respect to the matter discussed in Note 13, as to which the date is February 9, 2001). Our audit was made for the purpose of forming an opinion on the basic consolidated 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 consolidated 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
February 5, 2001 (except with respect to the matter discussed in Note 13, as
to which the date is February 9, 2001).
Page 125 of 129
Schedule II
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 2000
(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) Additional Reserve
(6) Expenses charged against reserve
(7) Reversal of rate refund reserve
Page 126 of 129
Schedule II
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 1999
(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) Write down of computers
(6) Sale of Service Center
(7) Additional Reserve
(8) Expenses charged against reserve
(9) Rate refund charged against reserve
Page 127 of 129
Schedule II
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 1998
(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) Write down of computers
(6) Retirement of equipment
(7) Additional Reserve
(8) Expenses charged against reserve
Page 128 of 129
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/ Francis J. Boyle
Francis J. Boyle, Senior Vice President,
Chief Financial Officer, and Treasurer
March 12,2001
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 indicated on March 12, 2001.
Signature
Title
Robert H. Young*
/s/ Francis J. Boyle
(Francis J. Boyle)
/s/ John J. Holtman
(John J. Holtman)
Frederic H. Bertrand*
Robert L. Barnett*
Rhonda L. Brooks*
Robert G. Clarke*
Timothy S. Cobb*
Luther F. Hackett*
Mary Alice McKenzie*
Janice L. Scites*
President and Chief Executive Officer and
Director (Principal Executive Officer)
Senior Vice President, Chief Financial Officer,
and Treasurer (Principal Financial Officer)
Vice President and Controller (Principal Accounting
Officer)
Chairman of the Board of Directors
Director
Director
Director
Director
Director
Director
Director
By: /s/ Francis J. Boyle
(Francis J. Boyle)
Attorney-in-Fact for each of the persons indicated.
Such signature has been affixed pursuant to a Power of Attorney filed
as an exhibit hereto and incorporated herein by reference thereto.
Page 129 of 129