Annual Report (Form 10-K), fiscal year 1993

Item 1. Business.
Overview.
Central Vermont Public Service Corporation (the "Company"), incorporated under the laws of Vermont on August 20, 1929, is engaged in the purchase, production, transmission, distribution and sale of electricity. The Company has various wholly and partially owned subsidiaries. These subsidiaries are described below.
The Company is the largest electric utility in Vermont and serves 133,658 customers in 175 of the 245 towns in Vermont. This represents about 50% of the Vermont population. In addition, the Company supplies electricity at wholesale to one rural cooperative, and one private utility.
The Company's sales are derived from a diversified customer mix. The Company's sales to residential, commercial and industrial customers accounted for 59% of total MWH sales for the year 1993. Sales to the five largest retail customers receiving electric service from the Company during the same period constituted about 4.5% of the Company's total electric revenues for the year. The Company's requirements resale sales accounted for approximately 6%, entitlement sales accounted for 27% and other resale sales which include contract sales, opportunity sales and sales to NEPOOL accounted for approximately 8% of total MWH sales for the year 1993.
Connecticut Valley Electric Company Inc. ("Connecticut Valley"), a wholly owned subsidiary of the Company, incorporated under the laws of New Hampshire on December 9, 1948, distributes and sells electricity in parts of New Hampshire bordering the Connecticut River. It serves 10,202 customers in 13 communities in New Hampshire. About 2% of the New Hampshire population resides in its service area. Connecticut Valley's sales are also derived from a diversified customer mix. Connecticut Valley's sales to residential, commercial and industrial customers accounted for 99.5% of total MWH sales for the year 1993. Sales to its five largest retail customers during the same period equaled about 17% of Connecticut Valley's total electric revenues for the year.
The Company also owns 56.8% of the common stock and 46.6% of the preferred stock of Vermont Electric Power Company, Inc. ("VELCO"). VELCO owns the high voltage transmission system in Vermont. VELCO created a wholly owned subsidiary, Vermont Electric Transmission Company, Inc. ("VETCO"), to finance, construct and operate the Vermont portion of the 450 KV DC transmission line connecting Quebec with Vermont and New England. In addition, the Company owns 31.3% of the common stock of Vermont Yankee Nuclear Power Corporation ("Vermont Yankee"), a nuclear generating company. The Company also owns 2% of the outstanding common stock of Maine Yankee Atomic Power Company, 2% of the outstanding common stock of Connecticut Yankee Atomic Power Company and 3.5% of the outstanding common stock of Yankee Atomic Electric Company.
The Company has two wholly owned subsidiaries that were created for the purpose of financing and constructing two hydroelectric facilities in Vermont: Central Vermont Public Service Corporation - Bradford Hydroelectric, Inc. ("Bradford"), which became operational December 20, 1982, and Central Vermont Public Service Corporation - East Barnet
Hydroelectric, Inc. ("East Barnet"), which became operational September 1, 1984. These hydro electric facilities have been leased and operated by the Company since their respective in-service dates. The Company also has the following wholly owned non-utility subsidiaries: C.V. Realty Inc., a real estate company, Catamount Energy Corporation whose purpose is to invest in energy-related projects, CV Energy Services, Inc. (a), whose purpose was to provide energy-related services and SmartEnergy Services, Inc., whose purpose is to cost effectively provide reliable energy efficient products and services, including the rental of electric water heaters.
Catamount Energy Corporation has established four wholly owned subsidiaries: (See "DIVERSIFICATION"); Catamount Rumford Corp., Equinox Vermont Corporation, Appomattox Vermont Corp. and Catamount Williams Lake L.P. See Exhibit EX-13 for additional information of the Company's diversification activities.
REGULATION AND COMPETITION
State Commissions.
The Company is subject to the regulatory authority of the Vermont Public Service Board ("PSB") with respect to rates, and the Company and VELCO are subject to PSB jurisdiction respecting securities issues, construction of major generation and transmission facilities and various other matters. The Company is subject to the regulatory authority of the New Hampshire Public Utilities Commission as to matters pertaining to construction and transfers of utility property in New Hampshire. Additionally, the Public Utilities Commission of Maine and the Connecticut Department of Public Utility Control exercise limited jurisdiction over the Company based on its ownership as a tenant-in-common of Wyman #4 and Millstone #3, respectively.
Connecticut Valley is subject to the regulatory authority of the New Hampshire Public Utilities Commission ("NHPUC") with respect to rates, securities issues and various other matters.
Federal Power Act.
Certain phases of the businesses of the Company and VELCO, including certain rates, are subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC"): the Company as a licensee of hydroelectric developments under Part I, and the Company and VELCO as interstate public utilities under Parts II and III, of the Federal Power Act, as amended and supplemented by the National Energy Act.
The Company has licenses expiring at various times under Part I of the Federal Power Act for twelve of its hydroelectric plants. The Company has obtained an exemption from licensing for the Bradford and East Barnet projects.
Public Utility Holding Company Act of 1935.
Although the Company, by reason of its ownership of utility subsidiaries, is a holding company, as defined in the Public Utility Holding Company Act of 1935, it is presently exempt, pursuant to Rule 2, promulgated by the Commission under said Act, from all the provisions of
said Act except Section 9(a)(2) thereof relating to the acquisition of securities of public utility affiliates. (a) CV Energy Services, Inc. was dissolved effective March 16, 1993.
Environmental Matters.
In recent years, public concern for the physical environment has resulted in increased governmental regulation of environmental matters. The Company is subject to these regulations in the licensing and operation of the generation, transmission, and distribution facilities in which it has interest, as well as the licensing and operations of the facilities in which it is a co-licensee. These environmental regulations are administered by local, state and Federal regulatory authorities and concern the impact of the Company's generation, transmission, distribution, transportation and waste handling facilities on air, water, land and aesthetic qualities.
The Company cannot presently forecast the costs or other effects which environmental regulation may ultimately have upon its existing and proposed facilities and operations, because the extent of the applicability is not known at this time. The Company believes that any such costs related to its utility operations would be recoverable through the rate-making process.
Refer to Exhibit EX-13 incorporated herein by reference for disclosures relating to environmental contingencies, hazardous substance releases and the control measures related thereto.
Nuclear Matters.
The nuclear generating facilities of Vermont Yankee and the other nuclear facilities in which the Company has an interest are subject to extensive regulations by the Nuclear Regulatory Commission ("NRC"). The NRC is empowered to regulate the siting, construction and operation of nuclear reactors with respect to public health, safety, environmental and antitrust matters. Under its continuing jurisdiction, the NRC may, after appropriate proceedings, require modification of units for which operating licenses have already been issued, or impose new conditions on such licenses, and may require that the operation of a unit cease or that the level of operation of a unit be temporarily or permanently reduced. Refer to Exhibit EX-13 incorporated herein by reference for disclosures relating to the shut down of the Yankee Atomic Nuclear Power plant.
Competition.
The Company's retail electric businesses in both Vermont and New Hampshire are generally free from competition by other electric utilities, municipalities or other public agencies. Pursuant to Vermont statutes (30 V.S.A. Section 249), the PSB has established as the service area for Central Vermont the area it now serves. Under 30 V.S.A. Section 251(b) no other company is legally entitled to serve any retail customers in the Company's established service area.
However, an amendment to 30 V.S.A. Section 212(a) enacted May 28, 1987 authorizes the Vermont Department of Public Service ("Department") to purchase and distribute power at retail to all customers of electricity in Vermont, subject to certain preconditions specified in new sections 212(b) and 212(c). Section 212(b) provides that a review board consisting of the
Governor and certain other designated legislative officers review and approve any retail proposal by the Department if they are satisfied that the benefits outweigh any potential risk to the State. However, the Department may proceed to file the retail proposal with the PSB either upon approval by the review board or the failure of the board to act within sixty (60) days of the submission. Section 212(c) provides that the Department shall not enter into any retail sales arrangement before the PSB determines and approves certain findings. Those findings are (1) the need for the sale, (2) the rates are just and reasonable, (3) the sale will result in economic benefit, (4) the sale will not adversely affect system stability and reliability and (5) the sale will be in the best interest of ratepayers.
Section 212(d) provides that upon PSB approval of the Department retail sales proposal, Vermont utilities shall make arrangements for distributing such electricity on terms and conditions that are negotiated. Failing such negotiation, the PSB is directed to determine such terms as will compensate the utility for all costs reasonably and necessarily incurred to provide such arrangements. See Rate Developments below for additional details involving retail sales by the Department.
In addition, Chapter 79 of Title 30 authorizes municipalities to acquire the electric distribution facilities located within their boundaries. The exercise of such authority is conditioned upon an affirmative three-fifths vote of the legal voters in an election and upon the payment of just compensation including severance damages. Once the price is determined, whether by agreement of the parties or by the PSB, a second affirmative three-fifths vote of the legal voters is required.
There has been only one instance where Chapter 79 of Title 30 has been invoked; the Town of Springfield acted to acquire the Company's distribution facilities in that community pursuant to a vote in 1977. This action was subsequently discontinued by agreement between Springfield and the Company in 1985.
No other municipality served by the Company, so far as is known to the Company, is taking steps in an attempt to establish a municipal electric distribution system.
For a discussion relating to the Company's wholesale electric business see "Wholesale Rates" below.
RATE DEVELOPMENTS
Vermont Retail Rates.
From July 1, 1985 through July 31, 1993, a block of energy obtained by the Department of Public Service (DPS) from the New York Power Authority (NYPA) and from Ontario Hydro was sold by the DPS directly to the Company's retail customers. When the DPS's sources were not sufficient, on a short-term basis, the Company provided back-up energy and capacity to meet the DPS's block requirements. Under this arrangement, which became effective July 1, 1989, the Company was reimbursed for all back-up energy and capacity.
During most of 1989 the DPS's block equaled the first 200 KWH sold to certain retail customers, but the block was reduced to 120 KWH beginning with bills rendered on December 1, 1989, to 85 KWH beginning with bills rendered on January 1, 1990, and to 75 KWH beginning with bills rendered
on February 3, 1992. Effective February 1, 1993, the DPS block was reduced to a maximum of 25 KWH from 75 KWH due to the termination of the Ontario Hydro power contract with the DPS on October 31, 1992. Since the Company sells to customers all KWH over the DPS's block, the Company's rates were reduced to provide the same net revenues under the 120, 85, 75, and 25 KWH blocks as they would have under the 200 KWH block. Effective February 1, 1992, the PSB allowed the Company to increase its billing and service fees charged to the DPS from 2.3 cents per KWH to 3.6 cents per KWH. The PSB subsequently delayed the effective date to December 1, 1992 but allowed the Company to collect the lost revenues plus interest after November 1, 1992 through a 3.0% surcharge on April and May 1993 bills.
On November 18, 1992, the Company filed with the PSB a tariff in response to expected and proposed changes to the provision of power by the DPS. The Company proposed to supply an initial non-seasonally differentiated block of 150 KWH/month to residential customers in the Company's service territory. On December 22, 1992, the DPS filed with the PSB to supply an initial block of 25 KWH/month to the Company's residential customers, reflecting the expiration, on October 31, 1992, of the Ontario Hydro power contract. On December 29, 1992, the PSB approved, on an interim basis pending investigation, a joint DPS-Company block of 150 KWH/month at a non-seasonal uniform rate of 8.4 cents per KWH. Initially, the DPS would sell the first 25 KWH and the Company would sell the remaining 125 KWH. The PSB's interim order resulted in a non-seasonal 25 KWH block at 5.2 cents per KWH for the DPS and a non-seasonal 125 KWH block at 9.0 cents per KWH for the Company. Accordingly, effective February 1, 1993, the DPS block was reduced to a maximum of 25 KWH from 75 KWH.
The remaining NYPA power allotment, which was the sole remaining power source of the DPS other than the Company, was reduced substantially effective July 1, 1993. Effective August 1, 1993, the DPS ceased altogether selling to the Company's retail customers. That NYPA power allotment is now sold directly to the Company and the retail sales formerly made by the DPS are now made by the Company. In addition, the Company's rates now provide for an initial non-seasonal 250 KWH block of sales to certain retail customers.
In response to a March 1993 PSB inquiry into the appropriateness of a general review of the Company's retail rates, in April 1993 the DPS and the Company entered into a Stipulation that was approved by the PSB in September 1993. In the Stipulation the Company agreed to a decrease in its allowed rate of return on common equity from 12.5% to 12.0% for 1993, to accelerate the recovery of $1.5 million of Conservation and Load Management ("C&LM") costs deferred in 1993, to not seek recovery of further C&LM costs deferred in 1993 equal to amounts in excess of the 12.0% rate of return on common equity for 1993, and to not file a general rate increase that would become effective before August 1, 1994. The PSB in its September 1993 order also announced the opening of an investigation on November 16, 1993, the earliest date the Company could file for a rate increase under the Stipulation, into the Company's cost of service and resulting rates.
In response to that investigation, on January 18, 1994 the Company filed a revenue requirement supporting a $16.1 million or 8.0% increase in retail rates for the year beginning November 1, 1993. The Company noted in its filing that current rate levels are justified and that the Company does not want any rate increase to be effective for that period. The Company also noted in its filing that rate relief would be needed in late 1994.
Thus on February 15, 1994, the Company filed for a rate increase of $17.9 million or 8.9% to become effective November 1, 1994.
The Company anticipates filing for rate increases periodically, primarily to recover increasing purchased power and other operating costs.
New Hampshire Retail Rates.
Connecticut Valley's retail rate tariffs, approved by the NHPUC, contain a fuel adjustment clause (FAC) and a purchased power cost adjustment clause (PPCA). Under these clauses, Connecticut Valley recovers its estimated annual costs for purchased energy and capacity, respectively, which are reconciled when actual data is available. Although the tariffs provide for annual changes of the FAC and PPCA effective January 1, the Company requested and the NHPUC approved a delay of the effective date to March 1, 1994. The NHPUC also ordered an interim increase in the PPCA effective December 1, 1993. On the basis of estimates of costs for 1994 and reconciliations from 1993, the combined PPCA and FAC will result in a decrease in revenues of approximately $16,000 or 0.1% for 1994.
Connecticut Valley filed in 1991 to redesign the revenue recovery from each rate component within each rate class, as well as from each rate class, to more accurately reflect the cost of service for each rate component and rate class. Negotiations with the NHPUC Staff resulted in a settlement rate design which was approved by the NHPUC effective in two steps: January 1, 1992 and March 1, 1992. The redesigned rates feature higher rates during the winter when Connecticut Valley is likely to experience a peak use of electricity. The settlement also provided for subsequent phases of rate redesign. Phase 2 resulted in an increase of the peak to off-peak season price ratio from 1.45 to 1.0 to a ratio of 1.6 to 1.0. This phase of rate redesign caused no change in the overall revenue requirement or the allocation of the revenue requirement among rate classes. The NHPUC approved this phase of rate redesign effective January 1, 1993. The NHPUC approved a delay of the effectiveness of Phase 3 to 1995.
Connecticut Valley's retail rate tariffs, approved by the NHPUC, also provide for Conservation and Load Management Percentage Adjustments (C&LMPA) for residential and commercial/industrial customers in order to collect deferred and forecast C&LM costs. The forecast costs are updated effective January 1 of each year and are reconciled when actual data are available. In addition, Connecticut Valley's earnings are made whole through recovery of lost revenues related to fixed costs which Connecticut Valley loses as a result of C&LM activities. However, the Company is not made whole because the fixed costs of the wholesale transaction between the Company and Connecticut Valley are not recovered when C&LM activities occur in Connecticut Valley. The C&LMPA further provides for the future recovery of shareholder incentives related to past C&LM activities.
The filing in September 1993 of the annual update of the 1994 C&LMPA rates resulted in a delay of the effective date to March 1, 1994 and a settlement on all issues except for one relating to the basis for determination of lost revenues. The NHPUC approved 1994 C&LMPA rates which result in a revenue decrease of $26,000 or 0.2%.
Effective July 1, 1993, the NHPUC allowed a revenue increase of $127,000 or 0.8% related to Connecticut Valley's adoption of the Statement
of Financial Accounting Standards No. 106 for Postretirement Benefits Other Than Pensions and the re-enactment of the New Hampshire Franchise Tax.
Connecticut Valley also purchases power from several independent power producers who own qualifying facilities under the Public Utility Regulatory Practices Act of 1978. Connecticut Valley filed a complaint with the Federal Energy Regulatory Commission (FERC) informing them of its concern that a solid waste facility owned and operated by Wheelabrator Claremont Company, L.P. has not been such a qualifying facility since the plant began operation. The outcome of this filing is unknown at this time. Potential outcomes of this filing could result in a refund, with interest, of past purchased power costs as well as lower future costs. Any refunds and future lower costs are likely to be reflected in the FAC when known. Connecticut Valley has petitioned the NHPUC for current recovery of costs related to pursuing this filing. Connecticut Valley has also petitioned for a deferral of such costs if a current recovery of these costs is not allowed by the NHPUC.
Wholesale Rates.
The Company sells firm power to Connecticut Valley under a wholesale rate schedule based on forecast data for each calendar year which is reconciled to actual data annually. The Company filed with the FERC for a revenue increase of $294,300 or 3.2% for 1994 power costs. The rate schedule provides for an automatic update of annual rates, as well as the subsequent reconciliation to actual data.
The Company sold firm system capacity to four Vermont village municipal electric departments ("Municipal Departments") under a wholesale tariff based on forecast data for each calendar year which is reconciled to actual data annually. As allowed in the tariff, the Company gave the Municipal Departments notice of extension of termination date of the tariff to October 21, 2008 from October 31, 1993. FERC approved the extension of the termination date. Due to current market conditions, the Municipal Departments did not opt to purchase power under this tariff during the period of the extension. Sales under the tariffs terminated October 31, 1993.
One of the Company's requirements wholesale customers, Woodsville Fire District Water and Light Department, with a peak of 3.6 MW began receiving power from the Company under a 15-year contract. The effective date was May 1, 1993 and the effect was to increase revenues from the customer.
Another of the Company's requirements wholesale customers, New Hampshire Electric Cooperative, Inc., with an average monthly peak of 2.8 MW has given the Company notice of termination of service under FERC Electric Tariff, First Revised Volume No. 1, effective in March 1995. The Company will continue to provide the transmission service and will enter into negotiations to supply power under another contract.
POWER RESOURCES
Overview.
The Company's and Connecticut Valley's energy production, which includes generated and purchased power, required to serve their retail and firm wholesale customers was 2,414,970 MWH for the year ended December 31,
1993. The maximum one-hour integrated demand during that period was 418.2 MW, which occurred on December 27, 1993. The Company's and Connecticut Valley's total production in 1993, including production related to all resale customers, was 3,651,319 MWH.
Wholly Owned Plants.
The Company owns and operates 18 hydroelectric generating facilities in Vermont which have an aggregate nameplate capability of 37.5 MW. It also leases and operates hydroelectric facilities at Bradford and East Barnet, Vermont. These two plants have a nameplate capability of 1.5 MW and 2.2 MW, respectively. In addition, the Company owns and operates diesel and gas turbine generating facilities on a peaking or standby basis having a combined nameplate capability of 28.9 MW.

The Company has a 1.73% joint-ownership interest in Millstone #3, an 1149 MW nuclear generating facility located in Waterford, Connecticut, which commenced commercial operation in April 1986. Under the Millstone Sharing Agreement, the Company is entitled to receive its share of the output and capacity of the facility and is responsible for its share of the operating expenses, including decommissioning.
The Company also has a 1.78% joint-ownership interest in Wyman #4, a 619 MW oil-fired generating facility located in Yarmouth, Maine and a 20% joint-ownership interest in McNeil, a 53 MW wood, gas and oil-fired generating facility located in Burlington, Vermont. The Company receives its share of the output and capacity from these generating plants and is responsible for its share of the operating expenses of each.
Finally the Company has a 46.08% joint-ownership interest in the Highgate Convertor, a 200 MW facility located in Highgate Springs, Vermont. This facility is directly connected to the Hydro-Quebec System to the north of the Convertor and to the VELCO System for delivery of power to Vermont Utilities. This facility can deliver power either direction, but normally delivers power from Hydro-Quebec to Vermont.
Equity Ownership in Plants.
In 1966 the Company purchased 35% of the Vermont Yankee common stock and was entitled to receive a like percentage of the output of the unit. In late 1969 and early 1970, the Company sold at cost a combined total of 3.7% of its original equity investment and currently resells at cost 4.7% of its entitlement. The Company's current equity ownership and net entitlement percentages are 31.3 and 30.5, respectively.
The Atomic Energy Commission, now the NRC, granted a full-term (40-year), full power operating license for the Vermont Yankee plant, which was to expire in December 2007. On December 17, 1990 the NRC issued an amendment of the operating license extending its term to March 2012.
 Vermont Yankee's net capability is 514 MW of which 156.7 MW (F1) is the Company's net entitlement. Vermont Yankee's plant performance for the past five years is shown below:
Availability Capacity Factor Factor (F2) (F3)
1989......................... 84.2 80.1 1990......................... 84.4 80.3 1991......................... 93.6 91.2 1992......................... 87.5 82.7 1993......................... 78.3 74.9
As was described in the overview section above, the Company is a stockholder, together with other New England electric utilities, in the following three nuclear generating companies: Maine Yankee Atomic Power Company, Connecticut Yankee Atomic Power Company and Yankee Atomic Electric Company.
Net Company's Company Capability Entitlement
Maine Yankee(F4).............. 847 MW 2.0% - 16.9 MW Connecticut Yankee............ 582 MW 2.0% - 11.6 MW Yankee Atomic................. (F5) (F5)
The Company is obligated to pay its entitlement percentage of the operating expenses of Vermont Yankee and the other Yankee companies, including depreciation and a return on invested capital, whether or not the plant is operating. The Company is obligated to contribute its entitlement percentage of the capital requirements of Vermont Yankee and Maine Yankee and has a similar, but more limited obligation to Connecticut Yankee. The Company's ownership percentages are identical to the entitlement percentages. For additional information regarding Equity Ownership in Plants, refer to Exhibit EX-13 incorporated herein by reference. _______________
(FN) (F1) Currently, the Company resells at cost, through VELCO, 23.2 MW of its original entitlement to other Vermont utilities.
(F2) "Availability Factor" means the hours that the plant is capable of producing electricity divided by the total hours in the period.
(F3) "Capacity Factor" means the total net electrical generation divided by the product of the maximum dependable electrical capacity multiplied by the total hours in the period.
(F4) Currently, the Company resells at cost 1.8 MW of its entitlement to certain municipal utilities in Massachusetts.
(F5) Yankee Atomic permanently ceased power operations of the Yankee Nuclear Power Station. See Decommissioning Expense discussion below.
Decommissioning Expense.
Each of the Yankee Companies has developed its own estimate of the cost of decommissioning its nuclear generating unit. These estimates vary
depending upon the method of decommissioning, economic assumptions, site and unit specific variables, and other factors. Each of the Yankee Companies includes charges for decommissioning costs in the cost of capacity, as approved by the FERC.
On February 26, 1992, the Board of Directors of Yankee Atomic decided to permanently discontinue operation of their plant, and, in time, decommission the facility. The decision to prematurely retire the plant was based on continuing regulatory uncertainty and economics.
The Company relied on Yankee Atomic for less than 1.5% of its system capacity. Presently, purchased power costs billed to the Company by Yankee Atomic, which include a provision for ultimate decommissioning of the unit, are being collected from the Company's customers via existing retail and wholesale rate tariffs.
On March 18, 1993, the FERC approved the settlement agreement regarding the decommissioning plan, recovery of plant investment and all issues with respect to prudency of the decision to discontinue operation. Yankee Atomic has estimated that as of December 31, 1993, its costs of discontinuing operations are approximately $345 million, which includes $200 million of decommissioning costs in 1992 dollars.
The Company's total current share of its cost with respect to Yankee Atomic's decision to discontinue operation is approximately $12 million. This amount is subject to ongoing review and revision and is reflected in the accompanying balance sheet both as a regulatory asset and deferred power contract obligation (current and non-current).
The Company believes that its proportionate share of Yankee Atomic costs will be recovered through the regulatory process and, therefore, the ultimate resolution of the premature retirement of the plant will not have a material adverse effect on the Company's earnings or financial condition.
Although the estimated costs of decommissioning are subject to change due to changing technologies and regulations, the Company expects that the nuclear generating companies' liability for decommissioning, including any future changes in the liability, will be recovered in their rates over their operating lives.
In 1982 the State of Maine enacted legislation that requires the development of a decommissioning trust fund for the Maine Yankee nuclear plant. This statute also provides that, if the trust has insufficient
funds to decommission the plant, the licensee, Maine Yankee, is responsible for the deficiency and, if the licensee is unable to provide the entire amount, the owners of the licensee are jointly and severally responsible for the remainder. The definition of owner under the statute includes the Company. It is expected that any payments required by the Company under these provisions would be recovered through rates.
Nuclear Fuel.
Vermont Yankee has approximately $165 million of "requirements based" purchase contracts for nuclear fuel needs to meet substantially all of its power production requirements through 2002. Under these contracts, any disruption of operating activity would allow Vermont Yankee to cancel or postpone deliveries until actually needed.
Vermont Yankee has contracted for uranium enrichment services through 2002. Vermont Yankee also has an enrichment contract with the DOE which expires in 2001. However, Vermont Yankee has exercised its right to partially terminate the DOE contract for the period 1990 to 1996.
Vermont Yankee has a contract with the United States Department of Energy ("DOE") for the permanent disposal of spent nuclear fuel. Under the terms of this contract, in exchange for the one-time fee discussed below and a quarterly fee of $.001 per KWH of electricity generated and sold, the DOE agrees to provide disposal services when a facility for spent nuclear fuel and other high-level radioactive waste is available, which is required by current statute to be prior to January 31, 1998.
The DOE contract obligates Vermont Yankee to pay a one-time fee of $39.3 million for disposal costs for all spent fuel discharged through April 7, 1983. Although such amount has been collected in rates from the Sponsors, Vermont Yankee has elected to defer payment of the fee to the DOE as permitted by the DOE contract. The fee must be paid no later than the first delivery of spent nuclear fuel to the DOE. Interest accrues on the unpaid obligation based on the thirteen-week Treasury Bill rate and is compounded quarterly.
Through 1993 Vermont Yankee deposited approximately $37.5 million, including $8.2 million in 1993, in an irrevocable trust to be used exclusively for defeasing this obligation at some future date provided the DOE complies with the terms of the aforementioned contract. In 1991 and 1992, Vermont Yankee deposited an additional amount of approximately $8.2 and $5.2 million, respectively, into this trust.
On December 31, 1991 the DOE issued a final rule amending the Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste. The amended final rule conforms with a March 17, 1989 ruling of the U.S. Court of Appeals for the District of Columbia that the $.001 per KWH fee in the Standard Contract should be based on net electricity generated and sold. The impact of the amendment on Vermont Yankee was to reduce the basis for the fee by 6% on an ongoing basis and to establish a receivable from the DOE at December 31, 1991 of $2.2 million for previous overbillings and accrued interest. Vermont Yankee has recognized in its rates the full impact of the amended final rule to the Standard Contract. The DOE is refunding the overpayments (including interest) to utilities over the next four year period ending in 1995 via credits against quarterly payments. Interest is based on the 90-day Treasury Bill Auction Bond Equivalent and will continue to accrue on amounts remaining to be credited. At December 31, 1993 and 1992
approximately $.9 and $1.6 million in principal and interest is reflected in other accounts receivable in the Vermont Yankee's Balance Sheet.
The average cost to the Company of energy generated at the Vermont Yankee plant was 4.04, 4.60, 3.69, 4.71 and 5.34 mills per KWH for the years 1989 through 1993, respectively.
The Company has been advised by the companies operating other nuclear generating stations in which the Company has an interest that they have contracted for certain segments of the nuclear fuel production cycle through various dates. Contracts for the remainder of the fuel cycle will be required but their availability, prices and terms cannot be predicted.
Nuclear Liability and Insurance.
For a complete disclosure regarding nuclear liability and insurance see Exhibit EX-13 incorporated herein by reference.
Major long-term purchases.
Canadian Purchases - Under various contracts, the Company purchases from Hydro-Quebec capacity and associated energy. Under the terms of these contracts, the Company is required to pay certain fixed capacity costs whether or not energy purchases above a minimum level described in the contracts are made. Such minimum energy purchases must be made whether or not other less expensive energy sources might be available.
The state of Vermont contract, between the Company and the Vermont Department of Public Service, terminates on September 22, 1995. The Company receives 69 MW of firm capacity and associated energy delivered at the Highgate interconnection.
The Company's portion of the 1987 Hydro-Quebec contract consists of: Schedule A, 25 MW of firm capacity and associated energy to be delivered at the Highgate interconnection through September 22, 1995. All of this power is being sold back to Hydro-Quebec for the duration of the contract. This sell-back of 25 MW continues as Schedule C-1 power at the termination of the Schedule A contract. This sell-back contract is not cancelable. Schedule C-1, 31 MW and Schedule C-2, 21 MW of firm capacity and associated energy are to be delivered at the NEPOOL/Hydro-Quebec (Phase I and Phase II) interconnection through October 2012. Under a cancelable contract, the Company is selling back to Hydro-Quebec 30 MW and 20 MW of its C-1 and C-2 entitlements, respectively, for the period ending October 31, 1996. Under the terms of this agreement, the Company can exercise an option, on an annual basis, to cancel all or any portion of this sell-back and resume deliveries of this power under the appropriate C-1 and C-2 schedules. Further agreements allow for the interruption of the sell-back, and the provision of 50 MW of capacity and delivery of associated energy for the period March through October of a given year. The Company must return this energy by the month of March of the following year or pay Hydro-Quebec 150% of the Schedule C-1 and Schedule C-2 energy price. Hydro-Quebec has the option under this sell-back agreement to buy back 50 MW for the period November 1, 1996 through October 31, 2000. This option must be exercised no later than October 31, 1994. These sell-back agreements provide the Company with the necessary flexibility to minimize near-term costs while retaining the long-term benefits of the purchase contracts. Schedule B, 92 MW of firm capacity and associated energy is expected to be delivered at the Highgate interconnection for 20-years beginning September 23, 1995. The Company will sell back 25 MW of
Schedule B entitlement for the period September 23 through October 31, 1995. Schedule C-4a, 24 MW of firm capacity and associated energy is expected to be delivered over the NEPOOL/Hydro-Quebec (Phase I and Phase II) interconnection beginning November 1, 1996 through October 31, 2012.
Merrimack #2 - Merrimack #2 is a 320 MW capacity coal-fired steam unit located in Bow, New Hampshire, and is owned and operated by Public Service Company of New Hampshire ("PSNH"). In 1968 VELCO contracted with PSNH to
purchase a block of 100 MW of the plant's output for 30 years and to pay a proportionate share of the plant's actual capacity and operating costs. Under an agreement dated February 10, 1968, between the Company and VELCO, the Company buys from VELCO at VELCO's cost 47.0 MW of that block for a 30-year period commencing May 1, 1968. Northeast Utilities (N.U.) has acquired all of PSNH's assets including the Merrimack #2 plant, pursuant to a merger agreement in 1991.
The Merrimack 2 unit is subject to limits on sulfur dioxide ("SO2") and Nitrogen Oxides ("NOx") starting in 1995, mandated by the Clean Air Act Amendments ("CAAA"). The CAAA establishes SO2 allowances to reduce SO2 emissions. PSNH expects to have sufficient SO2 allowances to meet CAAA SO2 requirements. If any gains are realized from the sale of excess allowances, the Company will receive its proportionate share from VELCO. Likewise, the Company will pay its share of any allowances purchased.
The CAAA NOx limits will be specified in Administrative Rules to be established by the state of New Hampshire. The New Hampshire Air Resources Division ("NHARD") has a proposed rule which includes Merrimack 2 NOx limits, that replaces a previous proposed rule submitted to the U.S. Environmental Protection Agency ("EPA") in 1993. The current proposed rule must be approved by the NHARD and the EPA, and implement the NOx reductions by May 31, 1995.
PSNH expects to comply with the current proposed Merrimack 2 NOx limits by installing Selective Noncatalytic Reduction equipment ("SNCR") and reducing load at Merrimack 2. Installation of the SNCR will increase capital and operating costs. PSNH will implement load reductions based on actual unit operating characteristics and dispatch, to comply with the NOx rule at the lowest cost. PSNH expects that an average load reduction of 22 per cent will be required for compliance. The Company will share on a pro-rata basis the SNCR and load reduction costs, based on its share of the VELCO contract.
Other Purchases.
Cogeneration/Small Power Qualifying - The Company continues to work with customers exploring the opportunities for either cogeneration by customers or the purchase by the Company of the output of small power qualifying. Cogeneration is the production of electricity and usable thermal energy from the same fuel. A number of small producers using hydroelectric, biomass, and refuse-burning generation are currently producing energy that the Company is purchasing. For the year ended December 31, 1993, the Company received 186,899 MWH from these sources for which it paid $18,213,351.
New York Power Authority - Prior to July 1, 1985, under agreements between the State and NYPA, the Department purchased St. Lawrence and Niagara Project power. The Company in turn contracted with the Department to purchase the St. Lawrence and Niagara Project power at cost, and credited the lower cost thereof to certain of the Company's retail customers.
From July 1, 1985 through July 31, 1993, the St. Lawrence and/or Niagara Project power was purchased by the DPS and sold directly to residential customers in the Company's service territory. This power is expected to be reduced to a minimum level in July 1994 and continue at that level through October 2003. For additional information regarding the
DPS's sales to the Company's residential customers see "Vermont Retail Rates".
The St. Lawrence Project power continues to be available to the Department but will be reduced each July 1 over a ten-year period until 1994, at which time the State will receive one MW of this power through 2002.
New England Power Pool - The Company, through VELCO, is a participant in the New England Power Pool ("NEPOOL"), which is open to all investor-owned, municipal and cooperative utilities in New England under an agreement in effect since 1971. The NEPOOL Agreement provides for joint planning and operation of generating and transmission facilities and also incorporates generating capacity reserve obligations and provisions regarding the use of major transmission lines and payment for such use. Because of its participation in NEPOOL, the Company's operating revenues and costs are affected to some extent by the operations of other participants in that agreement.
The primary purposes of NEPOOL are to provide energy reliability for the region, centralized economic dispatch and coordination of generation planning and construction by the individual participants. The Company's peak demand for 1993 occurred on December 27, 1993 and equaled 418.2 MW. At the time of this peak, the Company had a reserve margin of 21%. NEPOOL's peak for the year occurred on July 8, 1993 and totaled 19,570 MW. NEPOOL had a 26% reserve margin at the time of its 1993 peak.
Power Resources - Future.
The Company purchases about 90% of the power it needs, including the power it receives as part owner of the various Yankee nuclear plants. In 1993, about 35% of the Company's purchased power came from renewable sources, primarily water and wood. The Company's core business has no plans at this time to build any new generating facilities to supply power, instead it intends to satisfy customers' energy needs through a combination of power purchases and energy-efficiency services. Therefore, the Company uses a process called "integrated resource planning," or IRP, to help determine the resources necessary to meet future power needs. IRP is an evolving, on-going process. An interdisciplinary team representing various functional planning area works together continuously to coordinate and integrate planning. A Corporate Review Committee provides policy guidance and reviews resource investment recommendations from the IRP team. The primary objective of IRP is to provide reliable, least-cost energy resources consistent with the Company's policy to protect the environment. The choice of least-cost resources explicitly seeks a balance between traditional supply resources and energy efficiency investments with the Company's customers. Flexibility and diversity are investment guidelines designed to provide least-cost resources over a broad range of possible futures.
The Company does not currently plan to build generation resources. The resource plan calls for investments in energy efficiency through the 1990's with additional investments in energy-efficiency programs or power purchases beginning in the late 1990's. The energy efficiency and power purchase commitments made in the late 1980's served the Company and its shareholders well during the recent recessionary downturn. The resources from developers of cogeneration projects were deferred due to decreased need. Power purchases from Hydro-Quebec were deferred until the mid-1990's with the ability to recall on one-year notice. Energy
efficiency investments associated with new customers and new end-uses naturally declined during the period of reduced load growth. Thus the resource investment strategy with inherent flexibility and diversity provided near-term benefits with unpredictable changing economic conditions.
Based upon current load forecasts, the Company expects to be able to satisfy its load requirements into the mid-1990's through its ownership in various generating facilities and purchases from various other New England, New York, Canadian utilities, Independent Power Qualifying, and Conservation and Load Management. Current load and capacity forecasts for NEPOOL indicate adequate reserves and availability of power for the region as a whole into the late-1990's.
TRANSMISSION
Vermont Electric Power Company, Inc.
Since 1958 VELCO has been engaged in the operation of a high-voltage transmission system which interconnects the electric utilities in the State including the areas served by the Company. VELCO is also engaged in the business of purchasing bulk power for resale, at cost, to the Company and the other electric utilities (cooperative, municipal and investor-owned) in Vermont (the "Vermont utilities") and transmitting such power for the Vermont utilities. Refer to the notes to financial statements for a discussion of the 1985 Four Party Agreement between the Company, VELCO and two other major distribution companies in Vermont.
VELCO provides transmission services for the State of Vermont, acting by and through the Department, and for all of the electric distribution utilities in the State of Vermont. VELCO is reimbursed for its costs (as defined in the agreements relating thereto) for the transmission of power for such entities. The Company, as the largest electric distribution utility in Vermont, is the major user of VELCO's transmission system.
The Company owns 34,083 shares (56.8%) of the Class B common stock of VELCO, the balance being owned by other Vermont utilities. Each share of Class B common stock has one vote. The Company also owns 46,624 shares (46.6%) of the Class C preferred stock of VELCO, the balance being owned by other Vermont utilities. Shares of Class C preferred stock have no voting rights except the limited right to vote VELCO's shares of common stock in Vermont Electric Transmission Company, Inc. if certain dividend requirements are not met.
NEPOOL Arrangements.
VELCO participates for itself and as agent for the Company and twenty-one other Vermont utilities in NEPOOL (see "Business-New England Power Pool" for additional details).
Capitalization.
VELCO has authorized 92,000 shares of Class B common stock, $100 par value, of which 60,000 shares were outstanding on December 31, 1993 and 125,000 shares of Class C preferred stock, of which 100,000 shares were outstanding at December 31, 1993. On that date there were authorized and outstanding three issues of First Mortgage Bonds, aggregating $41,263,000, issued under an Indenture of Mortgage dated as of September 1, 1957, as amended, between VELCO and Bankers Trust Company, as Trustee (the "VELCO
Indenture"). The issuance of bonds under the VELCO Indenture is unlimited in amount but is subject to certain restrictions.
New transmission and associated facilities will be required by VELCO in 1994 to transmit power to Vermont utilities. The costs of such facilities are presently estimated at $1,833,000 including allowance for funds used during construction calculated at a rate of approximately 4.5%. For a description of VELCO's properties, see "VELCO" under Item 2.



Item 2. Properties.
The Company. The Company's properties are operated as a single system which is interconnected by transmission lines of VELCO, New England Power Company and PSNH. The Company owns and operates 21 small generating stations with a total current nameplate capability of 66,370 KW, has a 1.78% joint-ownership interest in an oil generating plant in Maine, has a 20% joint-ownership interest in a wood, gas and oil-fired generating plant in Vermont, has a 1.73% joint-ownership interest in a nuclear generating plant in Connecticut, has a 46.08% joint-ownership interest in a transmission interconnection with Hydro-Quebec in Vermont and leases and operates two hydro generating stations from wholly owned subsidiaries, Bradford and East Barnet, 1,500 KW and 2,200 KW, respectively.
The electric transmission and distribution systems of the Company include about 613 miles of overhead transmission lines, about 7,136 miles
of overhead distribution lines and about 192 miles of underground distribution lines which are located in Vermont except for about 23 miles of transmission lines which are located in New Hampshire and about two miles of transmission lines which are located in New York.
Connecticut Valley. Connecticut Valley's electric properties consist of two principal systems in New Hampshire which are not interconnected with each other but each of which is connected directly with facilities of the Company.
The electric systems of Connecticut Valley include about two miles of transmission lines and about 422 miles of overhead distribution lines and about nine miles of underground distribution lines.
All the principal plants and important units of the Company and its subsidiaries are held in fee. Transmission and distribution facilities which are not located in or over public highways are, with minor exceptions, located either on land owned in fee or pursuant to easements substantially all of which are perpetual. Transmission and distribution lines located in or over public highways are so located pursuant to authority conferred on public utilities by statute, subject to regulation of state or municipal authorities.
VELCO. VELCO's properties consist of about 483 miles of high voltage overhead transmission lines and associated substations. The lines connect on the west at the Vermont-New York state line with the lines of Niagara Mohawk Power Corporation near Whitehall, New York, and Bennington, Vermont and with the submarine cable of NYPA near Plattsburg, New York; on the south and east with lines of New England Power Company and PSNH; and on the south with the facilities of Vermont Yankee.
VETCO. VETCO has approximately 52 miles of high voltage DC transmission line connecting at the Quebec-Vermont border in the Town of Norton, Vermont with the transmission line of Hydro-Quebec and connecting at the Vermont-New Hampshire border near New England Power Company's Moore hydro-electric generating station with the transmission line of New England Electric Transmission Corporation, a subsidiary of New England Electric System.
Item 3.

Item 3. Legal Proceedings.
On December 5, 1991, Bonneville Pacific Corporation (Bonneville) filed for protection under Chapter 11 of the Bankruptcy Laws. On August 30, 1993, Bonneville's trustee in bankruptcy filed suit in the United States Bankruptcy Court in Utah, claiming damages in excess of two million dollars in connection with two contracts between Bonneville and the Company concerning the development of a 52 MW co-generation plant in Vermont and the sale of power from the plant to the Company. The Company and Bonneville have settled the case and Bonneville's claim has been dismissed with prejudice.
On March 20, 1992, Sunnyside Cogeneration Associates filed suit in the United States District Court for the District of Vermont against the Company, CV Energy Resources, Inc. (CVER) and a subsidiary of CVER alleging damages in excess of five million dollars resulting from the parties inability to come to agreement on the terms of CVER's proposed investment in the plaintiff's waste coal cogeneration facility under construction in Sunnyside, Utah. The Company has filed an answer denying
the allegations and does not expect the resolution of the case to have a material affect on the business or financial condition of the Company.
There are no other material pending legal proceedings, other than ordinary routine litigation incidental to the business, to which the Company or any of its subsidiaries is a party or to which any of their property is subject.
Item 4.

Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to security holders during the fourth quarter of 1993.
PART II
Item 5.

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.
(a) The Company's common stock is traded on the New York Stock Exchange ("NYSE") under the trading symbol CV.
The table below shows the high and low sales price of the Company's common stock, as reported on the NYSE composite tape by The Wall Street Journal, for each quarterly period during the last two years as follows:
Market Price High Low First quarter.............. $ 25 5/8 $ 24 1/8 Second quarter............. 25 1/8 22 Third quarter.............. 24 3/4 23 1/4 Fourth quarter............. 23 3/4 20 1/8
1992(F1) First quarter.............. $ 22 7/8 $ 19 5/8 Second quarter............. 21 1/4 19 1/2 Third quarter.............. 22 1/2 20 7/8 Fourth quarter............. 25 21 1/8 (FN) (F1)Retroactively adjusted to reflect the three-for-two stock split on February 11, 1993.
(b) As of December 31, 1993, there were 16,620 holders of the Company's common stock, $6 par value.
(c) Common stock dividends have been declared quarterly. Cash dividends of $.355 per share were paid for all quarters of 1993 and post-split cash dividends of $.3475 per share were paid for all quarters of 1992.
So long as any Senior Preferred Stock or Second Preferred Stock is outstanding, except as otherwise authorized by vote of two-thirds of each such class, if the Common Stock Equity (as defined) is, or by the declaration of any dividend will be, less than 20% of Total Capitalization (as defined), dividends on Common Stock (including all distributions thereon and acquisitions thereof), other than dividends payable in Common Stock, during the year ending on the date of such dividend declaration, shall be limited to 50% of the Net Income Available for Dividends on Common Stock (as defined) for that year; and if the Common Stock Equity
is, or by the declaration of any dividend will be, from 20% to 25% of Total Capitalization, such dividends on Common Stock during the year ending on the date of such dividend declaration shall be limited to 75% of the Net Income Available for Dividends on Common Stock for that year. The defined terms identified above are used herein in the sense as defined in subdivision 8A of the Company's Articles of Association; such definitions are based upon the unconsolidated financial statements of the Company. As of December 31, 1993, the Common Stock Equity of the Company was 52.7% of total capitalization.
For additional information regarding dividend restrictions see Exhibit EX-13 incorporated herein by reference.
Item 6.

Item 6. Selected Financial Data.
Information required to be furnished in response to this Item is submitted as Exhibit EX-13 incorporated herein by reference.
Item 7.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Information required to be furnished in response to this Item is submitted as Exhibit EX-13 incorporated herein by reference.
Item 8.


Item 8. Financial Statements and Supplementary Data.
Information required to be furnished in response to this Item is submitted as Exhibit EX-13 incorporated herein by reference.
Item 9.

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 Company's Articles of Incorporation and By-Laws provide for the division of the Board of Directors into three classes having staggered terms of office. In accordance with the Company's By-Laws, the Board of Directors has fixed at ten (10) the number of Directors for the ensuing year. The Directors whose terms will expire at the 1994 Annual Meeting of Stockholders are Frederic H. Bertrand, Mary Alice McKenzie and Robert D. Stout. Each of these Directors will stand for re-election to a three-year term expiring in 1997. Proxies will be voted (unless otherwise instructed) in favor of the election of the three nominees as indicated in the table below.
The following table sets forth certain information regarding the three nominees for Director, as well as all Directors presently serving on the Board whose terms will expire after the 1994 Annual Meeting. Each of the individuals listed in the table has been employed by the firm or has had the occupation set forth under his or her name for the past five years. In general, the business experience of each of these persons during this time was typical of a person engaged in the principal occupation listed for each.
Names and Principal Occupation Served as of Nominees and Directors Age Director Since
Nominees whose terms will expire in 1997:
FREDERIC H. BERTRAND 57 1984 Chairman of the Board and Chief Executive Officer, National Life Insurance Co. Montpelier, Vermont
MARY ALICE MCKENZIE 36 1992 President, John McKenzie Packing Co., Inc. Burlington, Vermont (Manufacturer of Meat Products)
ROBERT D. STOUT 67 1985 Retired President and Chief Executive Officer, Putnam Memorial Health Corporation Bennington, Vermont
Directors whose terms will expire in 1996:
ROBERT P. BLISS, JR. 70 1973 President, Bob Bliss, Ltd. St. Albans, Vermont (Insurance Industry Consultants)
ELIZABETH COLEMAN 56 1990 President, Bennington College Bennington, Vermont
PRESTON LEETE SMITH 63 1977 President and Chief Executive Officer, S-K-I Ltd. c/o Killington Ltd. Killington, Vermont (Ski Business)
THOMAS C. WEBB 59 1986 President and Chief Executive Officer, Central Vermont Public Service Corporation Rutland, Vermont
Directors whose terms will expire in 1995:
LUTHER F. HACKETT 60 1979 President, Hackett, Valine & MacDonald, Inc. Burlington, Vermont (Insurance Agents)
F. RAY KEYSER, JR. 66 1980 Chairman of the Board, Central Vermont Public Service Corporation, Of Counsel, Keyser, Crowley, Meub, Layden, Kulig & Sullivan, P.C. Rutland, Vermont (Lawyers)
GORDON P. MILLS 57 1980 Chairman, EHV-Weidmann Industries, Inc. St. Johnsbury, Vermont (Manufacturer of Electric Transformer Insulation)
The following table sets forth the names and ages of all executive officers of the Company, all positions and offices held within the Company, as well as work experience and positions held during the past five years. None of the executive officers of the Company has any family relationship with any other executive officer of the Company.
Executive Officers of the Registrant:
Name and Age Office Officer Since
Thomas C. Webb, 59 President and Chief Executive Officer 1985
Robert H. Young, 46 Executive Vice President and Chief Operating Officer 1987
Steven J. Allenby, 39(F1) Senior Vice President- Marketing and Customer Services 1985
Robert de R. Stein, 44 Senior Vice President- Engineering and Energy Resources 1988
Jacquel-Anne Chouinard, 54 Vice President-Human Resources 1986
Thomas J. Hurcomb, 56 Vice President-Marketing and Public Affairs 1975
Robert G. Kirn, 42 Vice President-Division Operations 1991
Donald L. Rushford, 63 Vice President and General Counsel 1972
Patricia A. Wakefield, 51(F1) Vice President-Marketing and Customer Services 1988
William J. Deehan, 41 Assistant Vice President-Rates and Economic Analysis 1991
Jonathan W. Booraem, 55 Treasurer 1984
James M. Pennington, 38 Controller 1993
Joseph M. Kraus, 39 Secretary and General Counsel 1987
Mr. Webb joined the Company in 1985 as Executive Vice President - Finance and Administration and in 1986 was also designated Chief Operating Officer. He was elected Director, President and Chief Executive Officer on July 1, 1986. From 1977 to 1985, Mr. Webb was employed by Central Maine Power Company as Senior Vice President - Finance and Administration and in other executive positions.
Mr. Young joined the Company in 1987 as Vice President - Finance and Administration. Mr. Young was named Senior Vice President - Finance and Administration in 1988, and in 1993 was elected Executive Vice President and Chief Operating Officer. During 1985-1986, he served as Senior Management Consultant for A. D. Little Co.
Mr. Stein joined the Company on June 1, 1988 as Assistant Vice President - Energy Planning. Mr. Stein was elected Vice President - Energy Supply Planning and Engineering effective January 1, 1990, and Senior Vice President - Engineering and Energy Resources in 1993. During the period 1984-1988, he served United Illuminating Company as Manager of Revenue Requirements and Manager of Generation Planning and Power Contracts.
Ms. Chouinard joined the Company in 1985 as Director - Human Resources. She was elected Assistant Vice President - Human Resources in 1986 and assumed her present position in 1988.
Mr. Hurcomb joined the Company in 1967 in the Marketing and customer Service area. He was elected Vice President - External Affairs in 1975, and Vice President - Marketing and Public Affairs in 1993.
Mr. Kirn joined the Company in 1991 as Vice President - Division Operations. From 1979 to 1991, he was employed by New York State Electric & Gas Corporation. He served as Operations Manager of the Lancaster Division Electric from 1988 until 1991 and as Operating Superintendent of the Berkshire District from 1985 to 1988.
Mr. Rushford joined the Company in 1972 and has served as Vice President and General Counsel since that time. Mr. Rushford retired effective January 1, 1994.
Mr. Deehan joined the Company in 1985. Prior to being elected to his present position, he served as Director of Rate Administration and Forecasting since 1987 and as Energy Forecaster from 1985-1987.
Mr. Booraem has been with the Company since 1969. Prior to being elected Treasurer in 1984, he was Director of Finance & Planning.
Mr. Kraus joined the Company in 1981 as Assistant Corporate Counsel. He was named Associate Corporate Counsel in 1983 and Senior Corporate Counsel in 1987. He was also elected Corporate Secretary and Senior Corporate Counsel in 1987 and Corporate Secretary and General Counsel effective January 1, 1994.
Mr. Pennington joined the Company in 1989 as Director of Taxes. He was named Director of Taxes and Plant Accounting in 1990. Mr. Pennington was designated Acting Controller effective July 19, 1992, and was elected
Controller and named Principal Accounting Officer in 1993. From 1984 to 1989, he served as Senior Tax Accountant for Northern Indiana Public Service Company. (FN) (F1) Steven J. Allenby and Patricia A. Wakefield resigned from the Company effective October 31, 1993.
The term of each officer is for one year or until a successor is elected.
Item 11.

Item 11. Executive Compensation.
The following table sets forth all cash compensation paid or to be paid by the Company and its subsidiaries, as well as the number of stock option awards earned during the last three fiscal years by the Company's Chief Executive Officer and the Company's four other most highly compensated policy making executive officers ("officer(s)") whose direct cash compensation for services rendered to the Company and its subsidiaries in all capacities exceeded $100,000.
STOCK OPTIONS
The following table sets forth options granted to the Company's chief executive officer and the Company's four other most highly compensated executive officers during 1993 under the Company's 1988 Stock Option Plan. Under SEC regulations, companies are required to project an estimate of appreciation of the underlying shares of stock during the option term. The Company has chosen the Black-Scholes model formula approved by the SEC. However, the ultimate value will depend on the market value of the Company's stock at a future date, which may or may not correspond to the projections below.
 The following table sets forth stock options exercised by the Company's Chief Executive Officer and the Company's four other most highly compensated executive officers during 1993, and the number and value of all unexercised options at year-end. The value of "in-the-money" options refers to options having an exercise price which is less than the market price of the Company's stock on December 31, 1993.
 DEFERRED COMPENSATION PLAN
Employees of the Company who are officers are eligible to defer receipt of a portion of their compensation pursuant to the Company's Deferred Compensation Plan for Officers. Also, certain of the Directors of the Company have elected to defer receipt of all or a portion of their fees under a similar plan for Directors.
Under the Plan approved effective January 1, 1990 Directors and Officers of the Company may elect to defer over a 5-year period receipt of a specified amount of compensation or fees otherwise currently payable to them until retirement at age 65 (age 70 for Directors), or until their death, disability, or resignation. Officers may receive a reduced benefit beginning at age 60 with 10 years of service. Amounts deferred are not currently taxable for state and Federal income taxes. The benefit is equal to the compensation deferred plus interest credited by the Company. This plan is a defined contribution program under which the Company recovers any costs, including the cost of capital, through the proceeds of the supporting life insurance policies. In addition, if death of a Director occurs before age 70, an additional survivor benefit equal to the annual amount deferred will be paid to the beneficiary each year for fifteen years. This benefit is also financed by life insurance proceeds.
PENSION PLAN
The Pension Plan of Central Vermont Public Service Corporation and Its Subsidiaries (the "Plan") covers employees, among others, who are officers. The Company pays the full cost of the Plan.
 The table below shows the annual amounts payable under the present provisions of the Plan as amended through December 31, 1993, based on Final Average Earnings for various years of service, assuming the employee would retire at age 65 in 1994.
Final Average Earnings is the highest five-year average of consecutive years' Base Salary (item (c) from the Summary Compensation Table) over an employee's career with the Corporation.
The amounts above are payable for the life of the retiree only, and would be reduced on an actuarial basis if survivor options were chosen. In addition, no Social Security offset applies to amounts above.
The credited years of service at December 31, 1993 under the Plan for those individuals named in the Summary Compensation Table were as follows: Mr. Webb, 9 years; Mr. Young, 6 years, 6 months; Mr. Stein, 5 years, 7 months; Mr. Rushford, 21 years, 6 months; and Mr. Hurcomb, 26 years.
OFFICERS' INSURANCE AND SUPPLEMENTAL RETIREMENT PLAN
The Officers' Insurance and Supplemental Retirement Plan (the "Plan") is designed to supplement the retirement benefits available to the Company's officers. The Plan is a part of the Company's overall strategy for attracting and maintaining top managerial talent in the utility industry. The Company pays the entire cost of the Plan.
Under the Plan, each officer is entitled to receive, upon his or her retirement at age 65, fifteen annual payments in amounts equal to a specified percentage of his or her final year's Base Salary (item (c) from the Summary Compensation Table). A reduced benefit is available at age 60 with ten years of service.
The applicable percentages for the individuals named in Summary Compensation Table are as follows: Mr. Webb, 44.5%; Mr. Young, 33%; Mr. Stein, 33%; Mr. Rushford, 33%; and Mr. Hurcomb, 33%.
Shown below is the estimated Company provided benefit payable at age 65 for those individuals named in the Summary Compensation Table who
receive a benefit under the Officers' Insurance and Supplemental Retirement Plan:
Assumed Final Annual Base Pay $ 33% 44.5%
80,000 26,400 35,600 100,000 33,000 44,500 120,000 39,600 53,400 140,000 46,200 62,300 160,000 52,800 71,200 180,000 59,400 80,100 220,000 72,600 97,900 260,000 85,800 115,700 300,000 99,000 133,500 340,000 112,200 151,300
PREDECESSOR DEFERRED COMPENSATION PLAN
Between 1986 and 1990, the Company allowed officers to defer receipt of compensation in return for fifteen annual payments of a defined benefit amount upon retirement. The Company will pay the difference, if any, between the defined benefit cost and the accumulated value of deferred compensation.
Shown below is the estimated Company-provided benefit, payable at age 65, for those individuals named in the Summary Compensation Table who elected to participate. Since these benefits do not apply to all of the named individuals, they have not been reflected in the foregoing pension table.
Annual Company- Provided Benefit Name Payable at Age 65
Mr. Webb $29,800 Mr. Rushford 19,700 Mr. Hurcomb 13,900
Item 12.

Item 12. Security Ownership of Certain Beneficial Owners and Management.
Section 16(a) of the Securities and Exchange Act of 1934 requires the Company's Officers and Directors to file reports of ownership and changes in ownership of Company securities with the Securities and Exchange Commission and to furnish the Company with copies of all such reports. In 1993, Director Mary Alice McKenzie inadvertently failed to file with the Securities and Exchange Commission on a timely basis one required report involving one transaction in Common Stock of the Company which she beneficially owns. Except for the foregoing, the Company believes that during 1993 all filing requirements applicable to its Officers and Directors have been met. In making this statement, the Company has relied on copies of reports that have been filed with the Commission.
Section 16(a) of the Securities Exchange Act of 1934 also requires executive officers and directors and persons who beneficially own more than ten percent (10%) of the Company's stock to file initial reports of
ownership and subsequent reports of changes in ownership with the SEC and the NYSE.
Based solely on a review of the copies of such forms prepared and filed during 1993 on behalf of our executive officers and directors, and on written representations that no other reports were required the Company believes its directors and executive officers have complied with all Section 16(a) filing requirements. The Company does not have a ten percent holder.
The following is a tabulation of equity securities of the Company beneficially owned by all present Directors and Executive Officers of the Company as a group (19 persons) as of January 31, 1994. No Director, nominee for Director or Executive Officer owns any shares of the various classes of the Company's outstanding non-voting preferred stock.
Title of Class Amount Beneficially Owned Percent of Class Common Stock, $6 Par Value 187,908 shares (F1) 1.6% (FN) (F1) Includes 124,625 shares that the directors and executive officers have a right to acquire pursuant to options granted under Stock Option plans.
The Company knows of no person, entity or group (within the meaning of Section 13(d)(3) of the Securities Exchange Act of 1934) which owns beneficially more than 5% of any class of the Company's outstanding equity securities.
Item 13.

Item 13. Certain Relationships and Related Transactions.
None.
Filed Herewith at Page PART IV
Item 14.

Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as part of this report:
1. Management's Discussion:
1.1 Central Vermont Public Service Corporation and its wholly owned subsidiaries: (See Item 7)
Management's Discussion and Analysis of Financial Condition and Results of Operations
 2. Financial Statements:
2.1 Central Vermont Public Service Corporation and its wholly owned subsidiaries: (See Item 8)
Consolidated Statement of Income, years ended December 31, 1993, 1992, and 1991.
Consolidated Statement of Cash Flows, years ended December 31, 1993, 1992 and 1991.
Consolidated Balance Sheet, December 31, 1993 and 1992.
Consolidated Statement of Capitalization, December 31, 1993 and 1992.
Consolidated Statement of Changes in Common Stock Equity, years ended December 31, 1993, 1992 and 1991.
Notes to Consolidated Financial Statements.
3. Financial Statement Schedules:
3.1 Central Vermont Public Service Corporation and its wholly owned subsidiaries:
Schedule V - Utility Plant, years ended December 31, 1993, 1992 and 1991.
Schedule VI - Accumulated Depreciation of Utility Plant, years ended December 31, 1993, 1992 and 1991.
Filed Herewith at Page PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K Continued.
Schedule VIII - Reserves, years ended December 31, 1993, 1992 and 1991.
Schedule IX - Short-term borrowings, years ended December 31, 1993, 1992 and 1991.
3.2 Financial Statements and Schedules for Vermont Yankee Nuclear Power Corporation - per index attached.
Schedules not included have been omitted because they are not applicable or the required information is shown in the financial statements or notes thereto. Separate financial statements of the Registrant (which is primarily
 an operating company) have been omitted since they are consolidated only with those of totally held subsidiaries. Separate financial statements of subsidiary companies not consolidated have been omitted since, if considered in the aggregate, they would not constitute a significant subsidiary. Other than Vermont Yankee Nuclear Power Corporation, separate financial statements of 50% or less owned persons for which the investment is accounted for by the equity method by the Registrant have been omitted since, if considered in the aggregate, they would not constitute a significant investment.
(b) Reports on Form 8-K:
There were no reports on Form 8-K for the quarter ended December 31, 1993.
(c) See exhibits index.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Central Vermont Public Service Corporation:
We have audited in accordance with generally accepted auditing standards, the consolidated financial statements included in Central Vermont Public Service Corporation's annual report to shareholders incorporated by reference in this Form 10-K, and have issued our report thereon dated February 7, 1994. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed in the index above are the responsibility of the Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly state, in all material respects, the consolidated financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Boston, Massachusetts, February 7, 1994
 Schedule V
CENTRAL VERMONT PUBLIC SERVICE CORPORATION AND ITS WHOLLY OWNED SUBSIDIARIES
 Schedule VI
CENTRAL VERMONT PUBLIC SERVICE CORPORATION AND ITS WHOLLY OWNED SUBSIDIARIES
Accumulated Depreciation Of Electric Plant And Amortization Of Nuclear Fuel
Years ended December 31, 1993, 1992 and 1991
 Schedule VIII
CENTRAL VERMONT PUBLIC SERVICE CORPORATION AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 1993
 Schedule VIII
CENTRAL VERMONT PUBLIC SERVICE CORPORATION AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 1992
 Schedule VIII
CENTRAL VERMONT PUBLIC SERVICE CORPORATION AND ITS WHOLLY OWNED SUBSIDIARIES
Reserves
Year ended December 31, 1991
 Schedule IX
CENTRAL VERMONT PUBLIC SERVICE CORPORATION AND ITS WHOLLY OWNED SUBSIDIARIES
Short-Term Borrowings
Years Ended December 31, 1993, 1992, 1991
Independent Auditor's Report
The Stockholders and Board of Directors Vermont Yankee Nuclear Power Corporation:
We have audited the accompanying balance sheet of Vermont Yankee Nuclear Power Corporation as of December 31, 1993, and the related statements of income and retained earnings and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of Vermont Yankee Nuclear Power Corporation as of December 31, 1992 and 1991, were audited by other auditors whose report, dated February 5, 1993, expressed an unqualified opinion on those statements and included an additional paragraph discussing the Company's 1992 change in accounting for postretirement benefits other than pensions.
We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Vermont Yankee Nuclear Power Corporation as of December 31, 1993, and the results of its operations and cash flows for the year then ended, in conformity with generally accepted accounting principles.
As discussed in note 10 of the accompanying financial statements, effective January 1, 1993 the Company adopted the provisions of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes".
Our audit was made for the purpose of forming an opinion on the basic financial statements taken as whole. The supplementary schedules are presented for purposes of additional analysis and are not a required part of the basic financial statements. This information has been subjected to the auditing procedures applied in our audit of the basic financial statements and, in our opinion, is fairly stated, in all material respects, in relation to the basic financial statements taken as a whole.
Arthur Andersen & Co.
Boston, Massachusetts January 27, 1994
VERMONT YANKEE NUCLEAR POWER CORPORATION
Index to Financial Statements and Financial Statement Schedules
Financial Statements:
Balance Sheets, December 31, 1993 and 1992
Statements of Income and Retained Earnings, years ended December 31, 1993, 1992 and 1991
Statements of Cash Flows, years ended December 31 ,1993, 1992 and 1991
Notes to Financial Statements
Financial Statement Schedules:
Schedule I - Marketable Securities and Other Investments at December 31, 1993
Schedule V - Property, Plant and Equipment, years ended December 31, 1993, 1992 and 1991
Schedule VI - Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment, years ended December 31, 1993, 1992 and 1991
All other schedules are omitted as the required information is inapplicable or the required information is included in the financial statements or related notes.
Balance Sheets Assets December 31, 1993 1992 (Dollars in thousands) Utility plant: Electric plant, at cost (note 6) $ 374,736 $ 362,278 Less accumulated depreciation 198,389 185,263 176,347 177,015 Construction work in progress 597 6,408
Net electric plant 176,944 183,423
Nuclear fuel, at cost (note 6): Assemblies in reactor 69,063 74,025 Fuel in process - 5,236 Spent fuel 287,700 259,199 356,763 338,460 Less accumulated amortization of burned nuclear fuel 317,039 302,362 39,724 36,098 Less accumulated amortization of final core nuclear fuel 7,220 6,487
Net nuclear fuel 32,504 29,611
Net utility plant 209,448 213,034
Current assets: Cash and temporary investments 2,349 1,922 Accounts receivable from sponsors 12,235 15,407 Other accounts receivable 4,522 2,715 Materials and supplies 17,081 16,862 Prepaid expenses 3,949 4,381
Total current assets 40,136 41,287
Deferred charges: Deferred decommissioning costs (note 2) 34,379 34,389 Accumulated deferred income taxes (note 10) 18,231 10,378 Deferred DOE enrichment site decontamination and decommissioning fee (note 4) 18,627 18,143 Net unamortized loss on reacquired debt 2,942 - Other deferred charges (note 4) 3,643 4,994
Total deferred charges 77,822 67,904
Long-term funds at amortized cost: Decommissioning fund (notes 2, 5, and 7) 98,880 82,091 Disposal fee defeasance fund (notes 5, 7, and 8) 43,484 33,892
Total long-term funds 142,364 115,983
$469,770 $438,208
See accompanying notes to financial statements.
Balance Sheets Capitalization and Liabilities
December 31, 1993 1992 (Dollars in thousands)
Capitalization: Common stock equity: Common stock, $100 par value; authorized 400,100 shares; issued 400,014 shares of which 7,533 are held in Treasury $ 40,001 $ 40,001 Additional paid-in capital 14,227 14,227 Treasury stock (7,533 shares at cost) (1,131) (1,131) Retained earnings 1,067 1,178
Total common stock equity 54,164 54,275
Long-term obligations, net (notes 6 and 7) 79,636 74,193
Total capitalization 133,800 128,468
Commitments and contingencies (notes 2, 14 and 15)
Disposal fee and accrued interest for spent nuclear fuel (notes 7 and 8) 80,688 78,239
Current liabilities: Accrued liabilities 28,063 22,743 Accounts payable 2,117 2,591 Accrued interest 635 974 Accrued taxes 1,206 1,472
Total current liabilities 32,021 27,780
Deferred credits: Accrued decommissioning costs (note 2) 134,614 117,601 Accumulated deferred income taxes 56,478 58,963 Net regulatory tax liability (note 10) 8,351 - Accumulated deferred investment tax credits 7,013 7,590 Net unamortized gain on reacquired debt - 1,732 Accrued DOE enrichment site decontamination and decommissioning fee (note 4) 15,966 17,220 Other deferred credits 839 615
Total deferred credits 223,261 203,721
$469,770 $438,208
See accompanying notes to financial statements.
Statements of Income and Retained Earnings Years ended December 31,
1993 1992 1991
(Dollars in thousands except per share amounts)
Operating revenues $180,145 $175,919 $151,722
Operating expenses: Nuclear fuel expense 19,526 21,240 24,864 Other operating expense 74,013 72,967 59,666 Maintenance 31,405 27,878 13,664 Depreciation 13,707 13,253 11,800 Decommissioning expense (note 2) 11,315 10,649 8,065 Taxes on income (note 10) 3,777 3,401 3,485 Property and other taxes 9,961 10,227 10,294 Total operating expenses 163,704 159,615 131,838
Operating income 16,441 16,304 19,884
Other income and (deductions): Net earnings on decommissioning fund (notes 2 and 5) 5,653 5,395 4,423 Decommissioning expense (note 2) (5,653) (5,395) (4,423) Allowance for equity funds used during construction 92 89 124 Interest 1,550 2,046 1,377 Taxes on other income (note 10) (623) (756) (447) Other, net (232) (199) (917) 787 1,180 137
Income before interest expense 17,228 17,484 20,021
Interest expense: Interest on long-term debt 7,281 7,101 7,684 Interest on disposal costs of spent nuclear fuel (note 8) 2,450 2,801 4,312 Allowance for borrowed funds used during construction (297) (339) (465) Total interest expense 9,434 9,563 11,531
Net income 7,794 7,921 8,490
Retained earnings at beginning of year 1,178 1,166 1,982 8,972 9,087 10,472 Dividends declared 7,905 7,909 9,306
Retained earnings at end of year $ 1,067 $ 1,178 $ 1,166
Average number of shares outstanding in thousands 392 392 394
Net income per average share of common stock outstanding $ 19.86 $ 20.18 $ 21.56
Dividends per average share of common stock outstanding $ 20.14 $ 20.15 $ 23.71
See accompanying notes to financial statements.
Statements of Cash Flows
Years ended December 31,
1993 1992 1991 (Dollars in thousands)
Cash flows from operating activities: Net income $7,794 $ 7,921 $ 8,490 Adjustments to reconcile net income to net cash provided by operating activities: Amortization of nuclear fuel 15,410 18,143 21,002 Depreciation 13,707 13,253 11,800 Decommissioning expense 11,315 10,649 8,065 Deferred tax expense (979) (2,169) (801) Amortization of deferred investment tax credits (577) (641) (740) Nuclear fuel disposal fee interest accrual 2,450 2,802 4,312 Interest and dividends on disposal fee defeasance fund (1,402) (1,385) (1,495) (Increase) decrease in accounts receivable 1,365 688 (129) (Increase) decrease in prepaid expenses 432 (1,159) 163 (Increase) in materials and supplies inventory (219) (454) (1,531) Increase (decrease) in accounts payable and accrued liabilities 4,846 (7,453) 5,495 Increase (decrease) in interest and taxes payable (605) 306 (760) Other (1,228) (1,410) (1,665)
Total adjustments 44,515 31,170 43,716
Net cash provided by operating activities 52,309 39,091 52,206
Cash flows from investing activities: Electric plant additions (7,229) (10,750) (6,596) Nuclear fuel additions (18,303) (4,707) (18,444) Payments to decommissioning fund (11,250) (10,612) (8,323) Payments to disposal fee defeasance fund (8,190) (5,190) (8,216) Net cash used in investing activities (44,972) (31,259) (41,579)
Cash flows from financing activities: Dividend payments (7,905) (7,909) (9,306) Purchase of treasury stock - - (1,131) Issuance of Series H first mortgage bonds, net - - 10,374 Issuance of Series I first
 mortgage bonds, net 75,125 - - Retirement of first mortgage bonds including redemption costs (74,629) (6,521) (13,178)
Payments of long-term obligations (137,911) (107,763) (53,419) Borrowings under long-term agreements 138,410 111,215 53,798 Net cash used in financing activities (6,910) (10,978) (12,862)
Net increase (decrease) in cash and temporary investments 427 (3,146) (2,235)
Cash and temporary investments at beginning of year 1,922 5,068 7,303
Cash and temporary investments at end of year $ 2,349 $ 1,922 $ 5,068
See accompanying notes to financial statements.
Notes to Financial Statements
NOTE 1. Summary of Significant Accounting Policies
(a) Regulations and Operations
Vermont Yankee Nuclear Power Corporation ("the Company") is subject to regulations prescribed by the Federal Energy Regulatory Commission ("FERC"), and the Public Service Board of the State of Vermont with respect to accounting and other matters. The Company is also subject to regulation by the Nuclear Regulatory Commission ("NRC") for nuclear plant licensing and safety, and by federal and state agencies for environmental matters such as air quality, water quality and land use.
Prior to November, 1993, the Company was subject to regulation by the Securities and Exchange Commission. As a result of the debt refinancing discussed in note 6, the Company is no longer subject to such regulation.
The Company recognizes revenue pursuant to the terms of the Power Contracts and Additional Power Contracts. The Sponsors, a group of nine New England utilities, are severally obligated to pay the Company each month their entitlement percentage of amounts equal to the Company's total fuel costs and operating expenses of its Plant, plus an allowed return on equity (since December 1, 1989, 12.25%). Such contracts also obligate the Sponsors to make decommissioning payments through the end of the Plant's service life and the completion of the decommissioning of the Plant. All Sponsors are committed to such payments regardless of the Plant's operating level or whether the Plant is out of service during the period.
Under the terms of the Capital Funds Agreements, the Sponsors are committed, subject to obtaining necessary regulatory authorizations, to make funds available to obtain or maintain licenses necessary to keep the Plant in operation.
(b) Depreciation and Maintenance
Electric plant is being depreciated on the straight-line method at rates
designed to fully depreciate all depreciable properties over the lesser of estimated useful lives or the Plant's remaining NRC license life, which extends to March, 2012. Depreciation expense was equivalent to overall effective rates of 3.74%, 3.56% and 3.23% for the years 1993, 1992 and 1991, respectively.
Renewals and betterments constituting retirement units are charged to electric plant. Minor renewals and betterments are charged to maintenance expense. When properties are retired, the original cost, plus cost of removal, less salvage, is charged to the accumulated provision for depreciation.
(c) Amortization of Nuclear Fuel
The cost of nuclear fuel is amortized to expense based on the rate of burn-up of the individual assemblies comprising the total core. The Company also provides for the costs of disposing of spent nuclear fuel at rates specified by the United States Department of Energy ("DOE") under a contract for disposal between the Company and the DOE.
The Company amortizes to expense on a straight-line basis the estimated costs of the final unspent nuclear fuel core, which is expected to be in place at the expiration of the Plant's NRC operating license in conformity with rates authorized by the FERC.
(d) Amortization of Materials and Supplies
The Company amortizes to expense a formula amount designed to fully amortize the cost of the material and supplies inventory that is expected to be on hand at the expiration of the Plant's NRC operating license.
(e) Long-term Funds
The Company accounts for its investments in long-term funds at amortized cost since it has both the intent and ability to hold these investments for the foreseeable future. Amortized cost represents the cost to purchase the investment, net of any unamortized premiums or discounts.
Notes to Financial Statements
NOTE 1. Summary of Significant Accounting Policies (Continued)
(f) Amortization of Gain and Loss on Reacquired Debt
The difference between the amount paid upon reacquisition of any debt security and the face value thereof, plus any unamortized premium, less any related unamortized debt expense and reacquisition costs, or less any unamortized discount, related unamortized debt expense and reacquisition costs applicable to the debt redeemed, retired and canceled, is deferred by the Company and amortized to expense on a straight-line basis over the remaining life of the applicable security issues.
(g) Allowance for Funds Used During Construction
Allowance for funds used during construction ("AFUDC") is the estimated cost of funds used to finance the Company's construction work in progress and nuclear fuel in process which is not recovered from the Sponsors through current revenues. The allowance is not realized in cash
currently, but under the Power Contracts, the allowance will be recovered in cash over the Plant's service life through higher revenues associated with higher depreciation and amortization expense.
AFUDC was capitalized at overall effective rates of 5.92%, 6.82% and 6.98% for 1993, 1992 and 1991, respectively, using the gross rate method.
(h) Decommissioning
The Company is accruing the estimated costs of decommissioning its Plant over the Plant's remaining NRC license life. Any amendments to these estimated costs are accounted for prospectively.
(i) Taxes on Income
Effective January 1, 1993, the Company began accounting for taxes on income under the liability method required by Statement of Financial Accounting Standard 109. See Note 10 for a further discussion of this change in accounting.
Investment tax credits have been deferred and are being amortized to income over the lives of the related assets.
(j) Cash Equivalents
For purposes of the Statements of Cash Flows, the Company considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents.
(k) Reclassifications
Certain information in the 1992 and 1991 financial statements has been reclassified to conform with the 1993 presentation.
(l) Earnings per Common Share
Earnings per common share have been computed by dividing earnings available to common stock by the weighted average number of shares outstanding during the year.
Notes to Financial Statements
NOTE 2. Decommissioning
The Company accrues estimated decommissioning costs for its nuclear plant over its remaining NRC licensed life based on studies by an independent engineering firm that assumes that decommissioning will be accomplished by the prompt removal and dismantling method. This method requires that radioactive materials be removed from the plant site and that all buildings and facilities be dismantled immediately after shutdown. Studies estimate that approximately six years would be required to dismantle the Plant at shutdown, remove wastes and restore the site. The Company has implemented rates based on a settlement agreement with the FERC which allowed $190 million, in 1988 dollars, as the estimated decommissioning cost. This allowed amount is used to compute the Company's liability and billings to the Sponsors. Based on an assumed inflation rate of 6% per annum and an expiration of the Plant's NRC operating license in 2012, the estimated current cost of decommissioning is $253 million and, at the end of 2012, is approximately $769 million.
The present value of the pro rata portion of decommissioning costs recorded to date is $134.6 million. On December 31, 1993, the balance in the Decommissioning Trust was $98.9 million.
Billings to Sponsors for estimated decommissioning costs commenced during 1983, at which time the Company recorded a deferred charge for the present value of decommissioning costs applicable to operations of the Plant for prior periods. Current period decommissioning costs not funded through billings to Sponsors or earnings on decommissioning fund assets are also deferred. These deferred costs will be amortized to expense as they are funded over the remaining life of the NRC operating license.
In 1994, the Company must file a revised estimate of decommissioning costs and a revised schedule of future annual decommissioning fund collections reflecting the historical differences between assumed and actual rates of inflation and the historical differences between assumed and actual rates of earnings on decommissioning fund assets. Filings are required to be made within four years of the most recent FERC approval of decommissioning cost estimates and rates.
Cash received from Sponsors for plant decommissioning costs is deposited into the Vermont Yankee Decommissioning Trust in either the Qualified Fund (i.e., amounts currently deductible pursuant to the IRS regulations) or the Nonqualified Fund (i.e., excess collections pursuant to FERC authorization which are not currently deductible). Funds held by the Trust are invested in high-grade U.S. government securities and municipal obligations. Interest earned by the Decommissioning Trust assets is recorded in other income and deductions, with an equal and offsetting amount representing the current period decommissioning cost funded by such earnings reflected as decommissioning expense.
Decommissioning expense for 1991 included an adjustment of approximately $2.1 million resulting from the Company's rate reduction filing approved by the FERC on February 28, 1991 as discussed in Note 3.
NOTE 3. FERC Rate Case Matters
On April 27, 1989, Vermont Yankee filed an application with the NRC to extend the term of the operating license from 2007 to 2012 so that the Plant may operate for 40 years after it entered commercial service in 1972. On December 17, 1990, the NRC issued an amendment to the operating license extending its term to March 21, 2012. The Company submitted a rate reduction filing with the FERC to reflect in rates the adjustments to decommissioning, depreciation and amortization resulting from the license extension. The Company proposed to make this reduction effective as of March 1, 1991 and, since the extension was issued in 1990, to reflect the necessary adjustment for the period January 1, 1990 through February 28, 1991.
On February 28, 1991, the FERC approved the Company's rate reduction filing. The effects of this ruling were accounted for prospectively in fiscal 1991, producing a net revenue reduction of approximately $7.4 million in 1991, which reflected the retroactive treatment to January 1, 1990. This ruling resulted in reduced revenue requirements of approximately $3.5 million for both 1992 and 1993, and similar reductions are expected in future years.
Notes to Financial Statements
NOTE 3. FERC Rate Case Matters (Continued)
On March 26, 1993, the FERC initiated a review of the return on common equity component of the formula rates included in the Company's Power Contracts. On October 22, 1993, the FERC approved a settlement whereby the Company retained its 12.25% authorized rate of return on common equity and agreed to credit monthly power billings by approximately $139,000 beginning in June, 1993.
In 1994, the Company will submit a rate filing to the FERC which will include, among other things, a revised estimate of decommissioning costs and a revised schedule of future annual decommissioning fund collections.
NOTE 4. Other Deferred Charges and Credits
In October, 1992, Congress passed the Energy Policy Act of 1992 which requires, among other things, that certain utilities help pay for the cleanup of the DOE's enrichment facilities over a 15-year period. The Company's annual fee is estimated based on the historical share of enrichment service provided by the DOE and is indexed to inflation. These fees will not be adjusted for future business as the DOE's future cost of sales will include a decontamination and decommissioning component. The Act stipulates that the annual fee shall be fully recoverable in rates in the same manner as other fuel costs.
In 1993, the DOE billed and the Company paid the first of the 15 annual fees. As of December 31, 1993, the Company has recognized a current accrued liability of $2.6 million for the two fee payments expected to be made in 1994, a deferred credit of $16.0 million for the 12 annual fee payments that are due subsequent to 1994 and a corresponding regulatory asset of $18.6 million which represents the total amount includable in future billings to the purchasers under the Power Contracts. While these amounts are reflected in these financial statements, the Company is reviewing the DOE's calculation of the annual fee and believes that the annual fee will ultimately be reduced.
Approximately $2.1 and $3.3 million of the $3.6 and $5.0 million in other deferred charges at December 31, 1993 and 1992, respectively, relate to payments made to the Vermont Low Level Radioactive Waste Authority ("VLLRWA"), an agency of the State of Vermont for the siting and construction of a low-level waste disposal facility.
NOTE 5. Long-term Funds
The book value and estimated market value of long-term fund investment securities at December 31, is as follows: 1993 1992
Book Market Book Market value value value value (Dollars in thousands) Decommissioning fund: U.S. Treasury obligations $17,262 18,666 $22,000 $23,067 Municipal obligations 79,755 84,576 57,141 59,009 Accrued interest and money market funds 1,863 1,863 2,950 2,950
98,880 105,105 82,091 85,026
 Disposal fee defeasance fund: Short-term investments 39,870 39,870 26,457 26,457 Corporate bonds and notes 3,195 3,083 6,110 5,940 Accrued interest and money market funds 419 419 1,325 1,325
43,484 43,372 33,892 33,722
Total long-term fund investments $142,364 $148,477 $115,983 $118,748
Notes to Financial Statements
NOTE 5. Long-term Funds (Continued)
At December 31, 1993 and 1992, gross unrealized gains and losses pertaining to the long-term investment securities were as follows: 1993 1992 (Dollars in thousands)
Unrealized gains on U.S. Treasury obligations $ 1,431 $ 1,071 Unrealized losses on U.S. Treasury obligations $ (27) $ (4) Unrealized gains on Municipal obligations $ 4,843 $ 1,895 Unrealized losses on Municipal obligations $ (22) $ (27) Unrealized losses on corporate bonds and notes $ (112) $ (170)
Maturities of short-term obligations, bonds and notes (face amount) at December 31, 1993 are as follows (dollars in thousands):
Within one year $42,200 Two to five years 16,977 Five to seven years 19,670 Over seven years 57,860
$136,707
NOTE 6. Long-term Obligations
A summary of long-term obligations at December 31, 1993 and 1992 is as follows: 1993 1992 (Dollars in thousands) First mortgage bonds: Series B - 8.50% due 1998 $ - $1,307 Series C - 7.70% due 1998 - 1,612 Series D - 10.125% due 2007 - 23,147 Series E - 9.875% due 2007 - 5,703 Series F - 9.375% due 2007 - 5,704 Series G - 8.94% due 1995 - 25,000 Series H - 8.25% due 1996 - 8,388 Series I - 6.48% due 2009 75,845 -
Total first mortgage bonds 75,845 70,861
Eurodollar Agreement Commercial Paper 3,791 3,292
Unamortized premium on debt - 40
Total long-term obligations $ 79,636 $ 74,193
The first mortgage bonds are issued under, have the terms and provisions set forth in, and are secured by an Indenture of Mortgage dated as of October 1, 1970 between the Company and the Trustee, as modified and supplemented by 13 supplemental indentures. All bonds are secured by a first lien on utility plant, exclusive of nuclear fuel, and a pledge of the Power Contracts and the Additional Power Contracts (except for fuel payments) and the Capital Funds Agreements with Sponsors.
On July 1, 1993, the Company retired the outstanding Series B and Series C first mortgage bonds. In November, 1993, the Company issued $75.8 million of Series I, first mortgage bonds stated to mature on November 1, 2009. The Company applied the proceeds of the bond issuance principally to retire the remaining Series D, Series E, Series F, Series G and Series H first mortgage bonds including call premiums totalling $3.7 million based on the early redemption of the bonds. Cash sinking fund requirements for the Series I first mortgage bonds are $5.4 million annually beginning in November, 1999.
The Company has a $75.0 million Eurodollar Credit Agreement that expires on December 31, 1995 subject to three optional one-year extensions. The Company issued commercial paper under this agreement with weighted average interest rates of 3.22% for 1993 and 3.95% for 1992. Payment of the commercial paper is supported by the Eurodollar Credit Agreement, which is secured by a second mortgage on the Company's generating facility.
Notes to Financial Statements
NOTE 7. Disclosures About the Fair Value of Financial Instruments
The carrying amounts for cash and temporary investments, trade receivables, accounts receivable from sponsors, accounts payable and accrued liabilities approximate their fair values because of the short maturity of these instruments. The fair values of long-term funds are estimated based on quoted market prices for these or similar investments. The fair values of each of the Company's long-term debt instruments are estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities.
The estimated fair value of the Company's financial instruments as of December 31 are summarized as follows (dollars in thousands): 1993 1992 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value
Decommissioning fund $98,880 $105,105 $82,091 $85,026 Disposal fee defeasance fund 43,484 43,372 33,892 33,722 Long-term debt 79,636 77,361 74,193 78,235 Disposal fee and accrued interest 80,688 80,688 78,239 78,239
Fair value estimates are made at a specific point in time, based on relevant market information and information about the financial instrument. These estimates are subjective in nature and involve uncertainties and matters of significant judgment and therefore cannot be
determined with precision. Changes in assumptions could significantly affect the estimates.
NOTE 8. Disposal Fee for Spent Nuclear Fuel
The Company has a contract with the United States Department of Energy ("DOE") for the permanent disposal of spent nuclear fuel. Under the terms of this contract, in exchange for the one-time fee discussed below and a quarterly fee of 1 mil per kwh of electricity generated and sold, the DOE agrees to provide disposal services when a facility for spent nuclear fuel and other high-level radioactive waste is available, which is required by current statute to be prior to January 31, 1998.
The DOE contract obligates the Company to pay a one-time fee of approximately $39.3 million for disposal costs for all spent fuel discharged through April 7, 1983. Although such amount has been collected in rates from the Sponsors, the Company has elected to defer payment of the fee to the DOE as permitted by the DOE contract. The fee must be paid no later than the first delivery of spent nuclear fuel to the DOE. Interest accrues on the unpaid obligation based on the thirteen-week Treasury Bill rate and is compounded quarterly. Through 1993, the Company deposited approximately $37.5 in an irrevocable trust to be used exclusively for defeasing this obligation at some future date, provided the DOE complies with the terms of the aforementioned contract.
On December 31, 1991, the DOE issued an amended final rule modifying the Standard Contract for Disposal of Spent Nuclear Fuel and/or High-level Radioactive Waste. The amended final rule conforms with a March 17, 1989 ruling of the U.S. Court of Appeals for the District of Columbia that the 1 mil per kilowatt hour fee in the Standard Contract should be based on net electricity generated and sold. The impact of the amendment on the Company was to reduce the basis for the fee by 6% on an ongoing basis and to establish a receivable from the DOE for previous overbillings and accrued interest. The Company has recognized in its rates the full impact of the amended final rule to the Standard Contract.
The DOE is refunding the overpayments, including interest, to utilities over a four-year period ending in 1995 via credits against quarterly payments. Interest is based on the 90-day Treasury Bill Auction Bond Equivalent and will continue to accrue on amounts remaining to be credited. At December 31, 1993 and 1992, respectively, approximately $0.9 and $1.6 million in principal and interest is reflected in other accounts receivable.
Notes to Financial Statements
NOTE 9. Short-term Borrowings
The Company had lines of credit from various banks totalling $6.3 million at December 31, 1993 and 1992. The maximum amount of short-term borrowings outstanding at any month-end during 1993, 1992 and 1991 was approximately $0.2 million, $0.6 million and $0.4 million, respectively. The average daily amount of short-term borrowings outstanding was approximately $0.3 million for 1993, and $0.1 million for 1992 and 1991 with weighted average interest rates of 5.75% in 1993, 6.12 % in 1992 and 8.19% in 1991. There were no amounts outstanding under these lines of credit as of December 31, 1993 and 1992.
NOTE 10. Taxes on Income
In February, 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes", which required the Company to change from the deferred method to the liability method of accounting for income taxes on January 1, 1993. The liability method accounts for deferred income taxes by applying enacted statutory rates in effect at the balance sheet date to differences between the book basis and the tax basis of assets and liabilities ("temporary differences").
This new statement requires recognition of deferred tax liabilities for (a) income tax benefits associated with timing differences previously passed on to customers and (b) the equity component of allowance for funds used during construction, and of a deferred tax asset for the tax effect of the accumulated deferred investment tax credits. It also requires the adjustment of deferred tax liabilities or assets for an enacted change in tax laws or rates, among other things.
Although adoption of this new statement has not and is not expected to have a material impact on the Company's cash flow, results of operations or financial position because of the effect of rate regulation, the Company was required to recognize an adjustment to accumulated deferred income taxes and a corresponding regulatory asset or liability to customers (in amounts equal to the required deferred income tax adjustment) to reflect the future revenues or reduction in revenues that will be required when the temporary differences turn around and are recovered or settled in rates. In addition, this new statement required a reclassification of certain deferred income tax liabilities to liabilities to customers in order to reflect the Company's obligation to flow back deferred income taxes provided at rates higher than the current 35% federal tax rate. The Company has applied the provisions of this new statement without restating prior year financial statements.
The components of income tax expense for the years ended December 31, 1993, 1992 and 1991 are as follows: 1993 1992 1991 (Dollars in thousands) Taxes on operating income: Current federal income tax $ 4,236 $ 4,926 $ 4,003 Deferred federal income tax (1,059) (1,840) (1,285) Current state income tax 1,097 1,285 1,024 Deferred state income tax 80 (329) 483 Investment tax credit adjustment (577) (641) (740)
3,777 3,401 3,485 Taxes on other income: Current federal income tax 496 598 353 Current state income tax 127 158 94
623 756 447
Total income taxes $ 4,400 $ 4,157 $ 3,932
Notes to Financial Statements
NOTE 10. Taxes on Income (Continued)
A reconciliation of the Company's effective income tax rates with the federal statutory rate is as follows:
1993 1992 1991
Federal statutory rate 35.0% 34.0% 34.0% State income taxes, net of federal income tax benefit 6.9 6.1 6.1 Investment credit (4.7) (5.3) (6.0) Book depreciation in excess of tax basis 2.0 1.9 1.7 AFUDC equity 0.6 0.9 0.9 Flowback of excess deferred taxes (3.6) (3.1) (6.7) Other (0.1) (0.1) 1.7
36.1% 34.4% 31.7%
The items comprising deferred income tax expense are as follows:
1993 1992 1991 (Dollars in thousands)
Decommissioning expense not currently deductible $ (351) $ (104) $ 14 Tax depreciation over (under) financial statement depreciation (978) (679) 955 Tax fuel amortization over (under) financial statement amortization (255) (637) (1,389) Tax loss on reacquisition of debt over (under) financial statement expense 1,887 187 178 Pension expense not currently deductible (167) (192) (562) Postemployment benefits deduction over (under) financial statement expense 67 (141) - Amortization of materials and supplies not currently deductible (335) (343) (239) Low-level waste deduction over (under) financial statement expense (596) 139 825 Flowback of excess deferred taxes (442) (376) (828) Other 191 (23) 245
$ (979) $ (2,169) $ (801)
Notes to Financial Statements
NOTE 10. Taxes on Income (Continued)
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at
December 31, 1993 and January 1, 1993 are presented below:
December 31, January 1, 1993 1993 (Dollars in thousands)
Deferred tax assets: Accumulated amortization of final nuclear core $ 2,914 $ 2,559 Nuclear decommissioning liability 2,810 2,291 Regulatory liabilities 5,856 6,793 Accumulated deferred investment credit 2,830 2,984 Accumulated amortization of materials and supplies 2,281 1,851 Other 2,771 4,591 Total gross deferred tax assets 19,462 21,069 Less valuation allowance 1,231 1,142 Net deferred tax assets 18,231 19,927
Deferred tax liabilities: Plant and equipment (51,258) (51,399) Other (5,220) (5,574) Total gross deferred tax liabilities (56,478) (56,973) Net deferred tax liability (38,247) (37,046)
The valuation allowance is the result of a provision in Vermont tax law which limits refunds resulting from carrybacks of net operating losses.
NOTE 11. Supplemental Cash Flow Information
The following information supplements the cash flow information provided in the Statements of Cash Flows:
1993 1992 1991 (Dollars in thousands) Cash paid during the year for: Interest (net of amount capitalized) $ 7,632 $ 7,062 $ 7,990
Income taxes $ 7,070 $ 6,192 $ 4,793
NOTE 12. Pension Plans
The Company has two noncontributory pension plans covering substantially all of its regular employees. The Company's funding policy is to fund the net periodic pension expense accrued each year. Benefits are based on age, years of service and the level of compensation during the final years of employment.
The aggregate funded status of the Company's pension plans as of December 31, 1993 and 1992 is as follows: December 31,
1993 1992 (Dollars in thousands)
Vested benefits $ 8,882 $ 6,548 Nonvested benefits 1,338 918 Accumulated benefit obligation 10,220 7,466
 Additional benefits related to future compensation levels 8,540 7,728
Projected benefit obligation 18,760 15,194 Fair value of plan assets, invested primarily in equities and bonds 16,343 13,791
Projected benefit obligation in excess of plan assets $ 2,417 $ 1,403
Notes to Financial Statements
NOTE 12. Pension Plans (Continued)
The increase in the projected benefit obligation from $15.2 million in 1992 to $18.8 million in 1993 is the result of additional service accruals, interest costs and changed plan assumptions.
Certain changes in the items shown above are not recognized as they occur, but are amortized systematically over subsequent periods. Unrecognized amounts still to be amortized and the amount that is included in the balance sheet appear below.
December 31,
1993 1992 (Dollars in thousands)
Unrecognized net transition obligation $ 996 $1,057 Unrecognized net gain (4,086) (4,939) Pension liability included in balance sheet 4,866 4,610 Unrecognized prior service costs 641 675
Projected benefit obligation in excess of plan assets $ 2,417 $ 1,403
The following are pension plan assumptions as of December 31, 1993 and 1992:
December 31,
1993 1992
Discount rate 7.0% 8.0% Compensation scale 5.5% 6.5% Expected return on assets 8.5% 8.5%
Net pension expense for the three years ending December 31, 1993 included the following components:
1993 1992 1991 (Dollars in thousands)
Service cost - benefits earned $ 1,141 $ 1,275 $ 1,147 Interest cost on projected benefit obligation 1,288 1,305 1,104 Actual (return) loss on plan assets (1,792) (867) (2,124) Net amortization and deferral 631 78 1,452
Net pension expense $ 1,268 $ 1,791 $ 1,579
NOTE 13. Postretirement Benefits Other Than Pensions
The Company adopted Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS 106), on January 1, 1992. This statement requires companies to use accrual accounting for postretirement benefits other than pensions. Prior to 1992, the Company accrued and collected a portion of postretirement benefits costs through decommissioning billings while the remaining cost was expensed when benefits were paid. The incremental cost, above the amount collected through decommissioning billings, approximately $2.4 million, is now accrued and since January, 1992, has been included in the Company's monthly power billings to Sponsors. The Company is funding this liability by placing monies in separate trusts. In order to maximize the deductible contributions permitted under IRS regulations, the Company has amended its pension plans and established separate VEBA trusts for management and union employees.
Notes to Financial Statements
NOTE 13. Postretirement Benefits Other Than Pensions (Continued)
In December, 1992, the FERC issued its policy statement setting forth how utilities can recover in rates the increased costs associated with the implementation of SFAS 106. The policy statement specifies three conditions that must be met before FERC will consider companies' election of the accrual method: (a) the Company must agree to make cash deposits to an irrevocable external trust fund, at least quarterly, in amounts that are proportional and, on an annual basis, equal to the annual test period allowance for postretirement benefits other than pensions; (b) the Company must agree to maximize the use of income tax deductions for contributions to funds of this nature; and (c) in order to recover the transition obligation, the Company must file a general rate change within three years of adoption of SFAS 106.
The following table presents the plan's funded status reconciled with amounts recognized in the Company's balance sheets as of December 31, 1993 and December 31, 1992 (dollars in thousands):
Accumulated postretirement benefit obligation: 1993 1992
Retirees $ 1,078 $ 1,277 Fully eligible active plan participants 921 1,332 Other active participants 8,071 9,935 Total accumulated postretirement benefit obligation 10,070 12,544
Fair value of plan assets, invested primarily in short-term investments 2,457 1,595 Accumulated postretirement benefit obligation in excess of plan assets $ 7,613 $10,949
Unrecognized net transition obligation $ 7,933 $10,314 Unrecognized net gain (1,980) (126) Accrued postretirement benefit cost
 collected through decommissioning billings and included in accrued liabilities 1,660 761
Accumulated postretirement benefit obligation in excess of plan assets $ 7,613 $ 10,949
The net periodic postretirement benefit cost for 1993 and 1992 includes the following components (dollars in thousands): 1993 1992
Service cost $ 735 $ 958 Interest cost 652 941 Net amortization and deferral 350 543
Net periodic postretirement benefit cost $ 1,737 $2,442
For measurement purposes, a 15% annual rate of increase in the per capita cost of covered benefits (i.e., health care cost trend rate) was assumed for 1993; the rate was assumed to decrease gradually to 6% by the year 2001 and remain at that level thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. For example, increasing the assumed health care cost trend rates by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 1993 by $2.2 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year ended December 31, 1993 by $0.3 million. The weighted-average discount rate used in determining the accumulated postretirement benefit obligation was 7% at December 31, 1993.
The change in the accumulated postretirement benefit obligation from $12.5 million in 1992 to $10.0 million in 1993 is the result of adjustments made to reflect a lower actual medical cost increase during 1993 than projected. The reduction in the unrecognized net transition obligation from $10.3 million in 1992 to $7.9 million in 1993 is primarily the result of elimination of Medicare Part B coverage.
Notes to Financial Statements
NOTE 14. Lease Commitments
The Company leases equipment and systems under noncancelable operating leases. Charges against income for rentals under these leases were approximately $3.7 million, $2.6 million and $3.7 million in 1993, 1992 and 1991, respectively. Minimum future rentals as of December 31, 1993 are as follows:
Annual Fiscal years ended rentals (Dollars in thousands)
1994 $ 3,283 1995 3,060 1996 2,878 1997 2,798 1998 and after 5,053
The Company has entered into an agreement with General Electric Capital Corporation to lease certain equipment being constructed by General Electric Corporation valued at approximately $29 million including installation costs. Under the lease agreement, the Company will make 120 monthly payments of $342,358 per month commencing on the later of (1) April 15, 1995 or (2) the commissioning date of the equipment. The lease will also include the sale and leaseback of a $2 million turbine rotor forging previously owned by the Company. The lease will be classified as an operating lease for accounting purposes.
The construction contract requires progress payments to be paid by Vermont Yankee prior to installation of the equipment. Just prior to delivery of the equipment, the lessor will reimburse Vermont Yankee for these payments and will continue to make the remaining payments until the commencement date of the lease. During the time period subsequent to equipment delivery before the equipment is commissioned, the Company will pay interim rent to the lessor based on the amount of outstanding progress payments. The final documentation of the lease is currently being negotiated, and if a final agreement cannot be reached, the Company would be responsible for substantial termination payments.
Low-level Waste
In February, 1993, the Vermont Public Service Board issued an order which requires the Company to pay its share of expenses incurred by the Vermont Low Level Radioactive Waste Authority for the period April, 1993 through June, 1994, currently capped at $4.5 million. In addition, in accordance with Vermont Act 296, the order established a fund for the long-term care of any eventual Vermont low-level waste disposal facility. Based on this order, the Company must make annual payments of approximately $0.8 million into the long-term care fund. Payments made to the VLLRWA, not pertaining directly to the siting and construction of a low-level waste disposal facility, are being expensed currently.
In parallel with siting a low-level radioactive waste facility in Vermont, there has been a three-state effort between Vermont, Maine, and Texas to form a compact to site such a facility in Texas. The Texas Legislature has approved, and Governor Ann Richards of Texas has signed into law, a bill that would form such a compact. On November 2, 1993, Maine voters ratified the compact. Early during its 1994 session, the Vermont Legislature is scheduled to vote to approve entry into the compact. Following approval by the Vermont Legislature, the compact will require approval of the U.S. Congress.
Notes to Financial Statements
NOTE 15. Commitments and Contingencies (Continued)
If the compact is successful and proceeds on schedule, Vermont Yankee would begin sending its waste to a Texas facility during 1997. Under the proposed compact, Vermont would pay the State of Texas $25 million ($12.5 million when the U.S. Congress ratifies the compact and $12.5 million when the facility opens). In addition, Vermont must pay $2.5 million ($1.25 million when Congress ratifies the compact and $1.25 million when the facility is licensed) for community assistance projects in Hudspeth County, Texas, where the facility is to be located. Vermont would also pay one-third of the Texas Low-Level Radioactive Waste Disposal Compact Commission's expenses until the facility opens. The Disposal fees for
generators in Vermont and Maine would then be set at a level that is the same for generators in Texas. The Company anticipates recovering the costs of the compact from sponsors.
Nuclear Fuel
The Company has approximately $165 million of "requirements based" purchase contracts for nuclear fuel needs to meet substantially all of its power production requirements through 2002. Under these contracts, any disruption of operating activity would allow the Company to cancel or postpone deliveries until actually needed.
Insurance
The Price-Anderson Act, as amended, currently limits public liability from a single incident at a nuclear power plant to $9.4 billion. Any damages beyond $9.4 billion are indemnified under an agreement with the NRC, but subject to Congressional approval. The first $200 million of liability coverage is the maximum provided by private insurance. The Secondary Financial Protection program is a retrospective insurance plan providing additional coverage up to $9.2 billion per incident by assessing retrospective premiums of $79.3 million against each of the 116 reactor units that are currently subject to the Program in the United States, limited to a maximum assessment of $10 million per incident per nuclear unit in any one year. The maximum assessment is to be adjusted at least every five years to reflect inflationary changes.
The above insurance covers all workers employed at nuclear facilities prior to January 1, 1988, for bodily injury claims. The Company has purchased a Master Worker insurance policy with limits of $200 million with one automatic reinstatement of policy limits to cover workers employed on or after January 1, 1988. Vermont Yankee's estimated contingent liability for a retrospective premium on the Master Workers policy as of December, 1993 is $3.1 million. The Secondary Financial Protection program referenced above provides coverage in excess of the Master Worker policy.
Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL II) to cover the costs of property damage, decontamination or premature decommissioning resulting from a nuclear incident. All companies insured with NEIL II are subject to retroactive assessments if losses exceed the accumulated funds available to NEIL II. The maximum potential assessment against the Company with respect to losses arising during the current policy year is $5.8 million at the time of a first loss and $12.3 million at the time of a subsequent loss. The Company's liability for the retrospective premium adjustment for any policy year ceases six years after the end of that policy year unless prior demand has been made.
Notes to Financial Statements
VERMONT YANKEE NUCLEAR POWER CORPORATION
Schedule I
Marketable Securities - Other Investments
(Dollars in Thousands)
__________________________________________________________________________
Name of Issuer and Number Cost of Market Amount Title of Each Issue of Shares Each Value of at Which or Units Issue Each Each Principal * Issue Portfolio Amounts of at of Equity Bonds and 12/31/93 Security Notes Issues and Each Other Security Issue Is Carried on the Balance Sheet
__________________________________________________________________________
Decommissioning fund:
U.S. Treasury obligations $ 16,252 $ 17,262 $ 18,666 $ 17,262 Municipal obligations 78,055 79,755 84,576 79,755 Money market funds and Accrued Interest 1,863 1,863 1,863 1,863 $ 96,170 $ 98,880 $105,105 $ 98,880
Disposal fee defeasance fund:
Short-term investments $ 40,200 $ 39,870 $ 39,870 $ 39,870 Corporate bonds and notes 3,200 3,195 3,083 3,195 Money market funds and Accrued Interest 419 419 419 419 $ 43,819 $ 43,484 $ 43,372 $ 43,484
* Cost includes accrued interest and amortization of premiums and discounts.
VERMONT YANKEE NUCLEAR POWER CORPORATION
Schedule V - Property, Plant and Equipment
Years Ended December 31, 1993, 1992, and 1991
($000)
1993 1992 1991
Electric Plant:
Land and land rights $ 1,397 $ 1,127 $ 984 Structures and improvements 61,887 61,868 61,515
Reactor, turbogenerator and accessory equipment 304,388 292,561 285,808 Transmission equipment 5,948 5,606 6,141 Other 1,116 1,116 1,116 Construction work in progress 597 6,408 4,188 375,333 368,686 359,752
Nuclear Fuel:
Assemblies in reactor 69,063 74,025 83,213 Fuel in process - 5,236 637 Fuel in stock - - 22,863 Spent fuel 287,700 259,199 227,040 356,763 338,460 333,753
Total $732,096 $707,146 $693,505
Neither total additions of $25,361,000, $15,167,000 or $25,002,000 nor total retirements of $411,000, $1,526,000, or $0 for the years ended December 31, 1993, 1992 and 1991, respectively, exceeded 10% of the utility plant balance at the end of the year.
VERMONT YANKEE NUCLEAR POWER CORPORATION
Schedule VI - Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment
Years Ended December 31, 1993, 1992 and 1991
(Dollars in Thousands)
Additions Other Balance Charged to Charges Balance Beginning Costs and and At End of Year Expenses Retirements (Deduct) of Year
Accumulated depreciation of electric plant: (F1) 1993 185,263 13,707 (411) (170) (B) 198,389 1992 173,827 13,253 (1,526) (291) (B) 185,263 1991 162,065 11,800 - ( 38) (B) 173,827
Accumulated amortization of nuclear fuel: 1993 308,848 19,526 - (4,115) (C) 324,259 1992 291,013 21,240 - (3,405) (C) 308,848 1991 270,011 24,864 - (3,862) (C) 291,013
Total accumulated depreciation and amortization 1993 494,111 33,234 (411) (4,286) 522,648 1992 464,840 34,493 (1,526) (3,696) 494,111 1991 432,076 36,664 - (3,900) 464,840 (FN) (F1) Electric plant is being depreciated on the straight-line method at rates designed to fully depreciate all depreciable properties by 2012. (See Note 1 to the financial statements).
(B) Represents net salvage and removal costs.
(C) Represents disposal costs of spent nuclear fuel.
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our report dated February 7, 1994 included or incorporated by reference in this Form 10-K, into Central Vermont Public Service Corporation's previously filed Registration Statements on Form S-8, File No. 33-22741, Form S-8, File No. 33-22742, Form S-8, File No. 33-58102, Form S-8, File No. 33-6200 and Form S-3, File No. 33-37095.
ARTHUR ANDERSEN & CO.
Boston, Massachusetts March 25, 1994
CONSENT OF INDEPENDENT AUDITORS
The Board of Directors Central Vermont Public Service Corporation:
We consent to the incorporation by reference in the Registration Statement on Form S-8, File No. 33-22741, Form S-8, File No. 33-22742, Form S-8, File No. 33-58102, Form S-8, File No. 33-6200, and Form S-3, File No. 33-37095, of our report dated February 5, 1993 relating to the balance sheet of Vermont Yankee Nuclear Power Corporation as of December 31, 1992 and the related statements of income and retained earnings and cash flows for each of the years in the two-year period ended December 31, 1992, which report is included in the December 31, 1993 Annual Report on Form 10-K of Central Vermont Public Service Corporation.
KPMG PEAT MARWICK
Boston, Massachusetts March 24, 1994
EXHIBIT INDEX
Each document described below is incorporated by reference to the files of the Securities and Exchange Commission, unless the reference to the document is marked as follows:
* - Document has heretofore been filed with the Commission as is incorporated by reference and made a part hereof.
Exhibit Number Description
3. Articles of Incorporation and By-Laws
3-1 By-Laws, as amended December 3, 1990. (Exhibit No. 3-1, 1990 10-K)
3-2 Articles of Association, as amended August 11, 1992. (Exhibit No. 3-2, 1992 10-K)
4. Instruments defining the rights of security holders including Indentures
Incorporated herein by reference:
B-1 Mortgage dated October 1, 1929, between the Company and Old Colony Trust Company, Trustee, securing the Company's First Mortgage Bonds. (Exhibit B-3, File No. 2-2364)
B-2 Supplemental Indenture dated as of August 1, 1936, supplemental to B-1. (Exhibit B-4 File No. 2364)
B-3 Copy of Supplemental Indenture dated as of November 15, 1943, supplemental to B-1. (Exhibit B-3, File No. 2-5250
B-4 Copy of Supplemental Indenture dated as of December 1, 1943, supplemental to B-1. (Exhibit No. B-4, File No. 2-5250)
B-5 Copy of directors' resolutions adopted December 14, 1943, establishing the Series C Bonds and dealing with other related matters, supplemental to B-1. (Exhibit B-5, File No. 2-5250)
B-6 Copy of Supplemental Indenture dated as of April 1, 1944 supplemental to B-1. (Exhibit No. B-6, File No. 2-5466)
B-7 Copy of Supplemental Indenture dated as of February 1, 1945, supplemental to B-1. (Exhibit 7.6, File No. 2-5615 (22-385)
B-8 Directors' resolutions adopted April 9, 1945, establishing the Series D Bonds and dealing with other matters, supplemental to B-1. (Exhibit 7.8, File No. 2-5615 (22-385)
B-9 Copy of Supplemental Indenture dated as of September 2, 1947,
 supplemental to B-1. (Exhibit 7.9, File No. 2-7489)
B-10 Copy of Supplemental Indenture dated as of July 15, 1948, and directors' resolutions establishing the Series E Bonds and dealing with other matters, supplemental to B-1. (Exhibit 7.10, File No. 2-8388)
B-11 Copy of Supplemental Indenture dated as of May 1, 1950, and directors' resolutions establishing the Series F Bonds and dealing with other matters, supplemental to B-1. (Exhibit 7.11, File No. 2-8388)
B-12 Copy of Supplemental Indenture dated August 1, 1951, and and directors'resolutions, establishing the Series G Bonds and dealing with other matters, supplemental to B-1. (Exhibit 7.12, File No. 2-9073)
B-13 Copy of Supplemental Indenture dated May 1, 1952, and directors' resolutions, establishing the Series H Bonds and dealing with other matters, supplemental to B-1. (Exhibit 4.3.13, File No. 2-9613)
B-14 Copy of Supplemental Indenture dated as of July 10, 1953, supplemental to B-1. (July, 1953 Form 8-K)
B-15 Copy of Supplemental Indenture dated as of June 1, 1954, and directors' resolutions establishing the Series K Bonds and dealing with other matters, supplemental to B-1. (Exhibit 4.2.16, File No. 2-10959)
B-16 Copy of Supplemental Indenture dated as of February 1, 1957 and directors' resolutions establishing the Series L Bonds and dealing with other matters, supplemental to B-1. (Exhibit 4.2.16, File No. 2-13321)
B-17 Copy of Supplemental Indenture dated as of March 15, 1960, supplemental to B-1. (March, 1960 Form 8-K)
B-18 Copy of Supplemental Indenture dated as of March 1, 1962, supplemental to B-1. (March, 1962 Form 8-K)
B-19 Copy of Supplemental Indenture dated as of March 2, 1964, supplemental to B-1. (March, 1964 Form 8-K)
B-20 Copy of Supplemental Indenture dated as of March 1, 1965, and directors' resolutions establishing the Series M Bonds and dealing with other matters, supplemental to B-1. (April, 1965 Form 8-K)
B-21 Copy of Supplemental Indenture dated as of December 1, 1966, and directors' resolutions establishing the Series N Bonds and dealing with other matters, supplemental to B-1. (January, 1967 Form 8-K)
B-22 Copy of Supplemental Indenture dated as of December 1, 1967, and directors' resolutions establishing the Series O Bonds and dealing with other matters, supplemental to B-1. (December, 1967 Form 8-K)
 B-23 Copy of Supplemental Indenture dated as of July 1, 1969, and directors' resolutions establishing the Series P Bonds and dealing with other matters, supplemental to B-1. (July, 1969 Form 8-K)
B-24 Copy of Supplemental Indenture dated as of December 1, 1969, and directors' resolutions establishing the Series Q Bonds January, and dealing with other matters, supplemental to B-1. (January, 1970 Form 8-K)
B-25 Copy of Supplemental Indenture dated as of May 15, 1971, and directors' resolutions establishing the Series R Bonds and dealing with other matters, supplemental to B-1. (May, 1971 Form 8-K)
B-26 Copy of Supplemental Indenture dated as of April 15, 1973, and directors' resolutions establishing the Series S Bonds and dealing with other matters, supplemental to B-1. (May, 1973 Form 8-K)
B-27 Copy of Supplemental Indenture dated as of April 1, 1975, and directors' resolutions establishing the Series T Bonds and dealing with other matters, supplemental to B-1. (April, 1975 Form 8-K)
B-28 Copy of Supplemental Indenture dated as of April 1, 1977, modifying B-1. (Exhibit 2.42, File No. 2-58621)
B-29 Copy of Supplemental Indenture dated as of July 29, 1977, and directors' resolutions establishing the Series U, V, W, and X Bonds and dealing with other matters, supplemental to B-1. (Exhibit 2.43, File No. 2-58621)
B-30 Copy of Thirtieth Supplemental Indenture dated as of September 15, 1978, and directors' resolutions establishing the Series Y Bonds and dealing with other matters, supplemental to B-1. (Exhibit B-30, 1980 Form 10-K)
B-31 Copy of Thirty-first Supplemental Indenture dated as of September 1, 1979, and directors' resolutions establishing the Series Z Bonds and dealing with other matters, supplemental to B-1. (Exhibit B-31, 1980 Form 10-K)
B-32 Copy of Thirty-second Supplemental Indenture dated as of June 1, 1981, and directors' resolutions establishing the Series AA Bonds and dealing with other matters, supplemental to B-1. (Exhibit B-32, 1981 Form 10-K)
B-33 Copy of Trust Indenture dated as of May 1, 1962, between the Company and Mellon National Bank and Trust Company, Trustee, relating to the Company's 4 7/8% Debentures due May 1, 1987. (Exhibit 4.2.24, File No. 2-26485)
B-34 Copy of Trust Indenture dated as of May 1, 1968, between the Company and The First National Bank of Boston, Trustee, relating to the Company's 7% Debentures due May 1, 1993. (May, 1986 Form 8-K)
 B-35 Copy of Trust Indenture dated as of April 1, 1970, between the Company and The First National Bank of Boston, Trustee, relating to the Company's 10 5/8% Debentures due April 1, 1995. (April, 1970 Form 8-K)
B-36 Copy of Indenture of Mortgage, dated as of September 1, 1957, between Vermont Electric Power Company, Inc. ("Velco") and Bankers Trust Company, securing Velco's First Mortgage Bonds. (Exhibit (b)(1), 1957 Form 10-K)
B-37 Copy of Supplemental Indenture dated as of December 1, 1958, modifying B-36. (Exhibit (b)(1), 1958 Form 10-K)
B-38 Copy of Supplemental Indenture dated as of December 1, 1969, modifying B-36. (Exhibit 2.35, File 2-57458)
B-39 Copy of Supplemental Indenture dated as of November 1, 1970, modifying B-36. (Exhibit 2.36, File No. 2-57458)
B-40 Copy of Supplemental Indenture dated as of December 1, 1971, modifying B-36. (Exhibit 2.37, File No. 2-57458)
B-41 Copy of Supplemental Indenture dated as of December 1, 1972, modifying B-36. (Exhibit 2.38, File No. 2-57458)
B-42 Copy of Supplemental Indenture dated as of July 1, l974, modifying B-36. (Exhibit 2.39, File No. 2-57458)
B-43 Copy of Supplemental Indenture dated as of January 1, 1975, modifying B-36. (Exhibit 2.40, File No. 2-57458)
B-44 Copy of Supplemental Indenture dated as of January 1, 1979, modifying B-36. (Exhibit B-44, 1981 Form 10-K)
B-45 Copy of Thirty-third Supplemental Indenture dated as of August 15, 1983, and directors' resolutions establishing the Series BB Bonds and dealing with other matters, supplemental to B-1. (Exhibit B-45, 1983 Form 10-K)
B-46 Copy of Bond Purchase Agreement between Merrill, Lynch, Pierce, Fenner & Smith, Inc., Underwriters and The Industrial Development Authority of the State of New Hampshire, issuer and Central Vermont Public Service Corporation. (Exhibit B-46, 1984 Form 10-K)
B-47 Copy of Thirty-Fourth Supplemental Indenture dated as of January 15, 1985, and directors' resolutions establishing the Series CC Bonds and Series DD Bonds and matters connected therewith, supplemental to B-1. (B-47, 1985 Form 10-K)
B-48 Copy of Bond Purchase Agreement among Connecticut Development Authority and Central Vermont Public Service Corporation with E. F. Hutton & Company Inc. dated December 11, 1985. (Exhibit B-48, 1985 Form 10-K)
B-49 Stock-Purchase Agreement between Vermont Electric Power Company, Inc. and the Company dated August 11, 1986 relative to purchase of Class C Preferred Stock. (Exhibit B-49, 1986
 Form 10-K)
4-50 Copy of Thirty-Fifth Supplemental Indenture dated as of December 15, 1989 and directors' resolutions establishing the Series EE, Series FF and Series GG Bonds and matters connected therewith, supplemental to B-1. (Exhibit 4-50, 1989 Form 10-K)
4-51 Copy of Thirty-Sixth Supplemental Indenture dated as of December 10, 1990 and directors' resolutions establishing the Series HH Bonds and matters connected therewith, supplemental to B-1. (Exhibit 4-51, 1990 Form 10-K)
4-52 Copy of Thirty-Seventh Supplemental Indenture dated December 10, 1991 and directors' resolutions establishing the Series JJ Bonds and matters connected therewith, supplemental to B-1. (Exhibit 4-52, 1991 Form 10-K)
* 4-53 Copy of Thirty-Eight Supplemental Indenture dated December 10, 1993 establishing Series KK, LL, MM, NN, OO supplemental to B-1 (Exhibit 4-53, 1993 Form 10-K)
10. Material Contracts (*Denotes filed herewith)
Incorporated herein by reference:
10.l Copy of firm power Contract dated August 29, 1958, and supplements thereto dated September 19, 1958, October 7, 1958, and October 1, 1960, between the Company and the State of Vermont (the "State"). (Exhibit C-1, File No. 2-17184)
10.1.1 Agreement setting out Supplemental NEPOOL Understandings dated as of April 2, 1973. (Exhibit C-22, File No. 5-50198)
10.2 Copy of Transmission Contract dated June 13, 1957, between Velco and the State, relating to transmission of power. (Exhibit C-2, 1957 Form 10-K)
10.2.1 Copy of letter agreement dated August 4, 1961, between Velco and the State. (Exhibit C-3, File No. 2-26485)
10.2.2 Amendment dated September 23, 1969. (Exhibit C-4, File No. 2-38161)
10.2.3 Amendment dated March 12, 1980. (Exhibit C-92, 1982 Form 10-K)
10.2.4 Amendment dated September 24, 1980. (Exhibit C-93, 1982 Form 10-K)
10.3 Copy of subtransmission contract dated August 29, 1958, between Velco and the Company (there are seven similar contracts between Velco and other utilities). (Exhibit C-5, 1957 Form 10-K)
10.3.1 Copies of Amendments dated September 7, 196l, November 2, 1967, March 22, 1968, and October 29, 1968. (Exhibit C-6, File No. 2-32917)
 10.3.2 Amendment dated December 1, 1972. (Exhibit C-91, 1982 Form 10-K)
10.4 Copy of Three-Party Agreement dated September 25, 1957, between the Company, Green Mountain and Velco. (Exhibit C-7, File No. 2-17184)
10.4.1 Superseding Three Party Power Agreement dated January 1, 1990. (Exhibit 10-201, 1990 Form 10-K)
10.4.2 Agreement Amending Superseding Three Party Power Agreement dated May 1, 1991. (Exhibit 10.4.2, 1991 Form 10-K)
10.5 Copy of firm power Contract dated December 29, 1961, between the Company and the State, relating to purchase of Niagara Project power. (Exhibit C-8, File No. 2-26485)
10.5.1 Amendment effective as of January 1, 1980. (Exhibit C-51, 1980 Form 10-K)
10.6 Copy of agreement dated July 16, 1966, and letter supplement dated July 16, 1966, between Velco and Public Service Company of New Hampshire relating to purchase of single unit power from Merrimack II. (Exhibit C-9, File No. 2-26485)
10.6.1 Copy of Letter Agreement dated July 10, 1968, modifying Exhibit A. Exhibit C-10, File No. 2-32917)
10.7 Copy of Capital Funds Agreement between the Company and Vermont Yankee dated as of February 1, 1968. (Exhibit C-11, File No. 70-4611)
10.7.1 Copy of Amendment dated March 12, 1968. (Exhibit C-12, File No. 70-4611)
10.8 Copy of Power Contract between the Company and Vermont Yankee dated as of February 1, 1968. (Exhibit C-13, File No. 70-4591)
10.8.1 Amendment dated April 15, 1983. (C-106, 1983 Form 10-K)
10.8.2 Copy of Additional Power Contract dated February 1, 1984. (Exhibit C-123, 1984 Form 10-K )
10.8.3 Amendment No. 3 to Vermont Yankee Power Contract, dated April 24, 1985. (Exhibit 10-144, 1986 Form 10-K)
10.8.4 Amendment No. 4 to Vermont Yankee Power Contract, dated June 1, 1985. (Exhibit 10-145, 1986 Form 10-K)
10.8.5 Amendment No. 5 dated May 6, 1988. (Exhibit 10-179, 1988 Form 10-K)
10.8.6 Amendment No. 6 dated May 6, 1988. (Exhibit 10-180, 1988 Form 10-K)
10.8.7 Amendment No. 7 dated June 15, 1989. (Exhibit 10-195,
 1989 Form 10-K)
10.9 Copy of Capital Funds Agreement between the Company and Maine Yankee dated as of May 20, 1968. (Exhibit C-14, File No. 70-4658)
10.9.1 Amendment No. 1 dated August 1, 1985. (Exhibit C-125, 1984 Form 10-K )
10.10 Copy of Power Contract between the Company and Maine Yankee dated as of May 20, 1968. (Exhibit C-15, File No. 70-4658)
10.10.1 Amendment No. 1 dated March 1, 1984. (Exhibit C-112, 1984 Form 10-K)
10.10.2 Amendment No. 2 effective January 1, 1984. (Exhibit C-113, 1984 Form 10-K)
10.10.3 Amendment No. 3 dated October 1, 1984. (Exhibit C-114, 1984 Form 10-K)
10.10.4 Additional Power Contract dated February 1, 1984. (Exhibit C-126, 1985 Form 10-K)
10.11 Copy of Agreement dated January 17, 1968, between Velco and Public Service Company of New Hampshire relating to purchase of additional unit power from Merrimack II. (Exhibit C-16, File No. 2-32917)
10.12 Copy of Agreement dated February 10, 1968 between the Company and Velco relating to purchase by Company of Merrimack II unit power. (There are 25 similar agreements between Velco and other utilities.) (Exhibit C-17, File No. 2-32917)
10.13 Copy of Three-Party Power Agreement dated as of November 21, 1969, among the Company, Velco, and Green Mountain relating to purchase and sale of power from Vermont Yankee Nuclear Power Corporation. (Exhibit C-18, File No. 2-38161)
10.13.1 Amendment dated June 1, 1981. (Exhibit C-59, 1981 Form 10-K)
10.14 Copy of Three-Party Transmission Agreement dated as of November 21, 1969, among the Company, Velco, and Green Mountain providing for transmission of power from Vermont Yankee Nuclear Power Corporation. (Exhibit C-19, File No. 2-38161)
10.14.1 Amendment dated June 1, 1981. (Exhibit C-60, 1981 Form 10-K)
10.15 Copy of Stockholders Agreement dated March 29, 1957, between the Company, Velco, Green Mountain and Citizens Utilities Company. (Exhibit No. C-20, File No. 70-3558)
10.16 New England Power Pool Agreement dated as of September 1, 1971, as amended to November 1, 1975. (Exhibit C-21, File No. 2-55385)
 10.16.1 Amendment dated December 31, 1976. (Exhibit C-52, 1980 Form 10-K)
10.16.2 Amendment dated January 23, 1977. (Exhibit C-53 1980 Form 10-K)
10.16.3 Amendment dated July 1, 1977. (Exhibit C-54, 1980 Form 10-K)
10.16.4 Amendment dated August 1, 1977. (Exhibit C-55, 1980 Form 10-K)
10.16.5 Amendment dated August 15, 1978. (Exhibit C-56, 1980 Form 10-K)
10.16.6 Amendment dated January 31, 1979. (Exhibit C-57 1980 Form 10-K)
10.16.7 Amendment dated Feburary 1, 1980. (Exhibit C-58, 1980 Form 10-K)
10.16.8 Amendment dated December 31, 1976. (Exhibit C-72, 1981 Form 10-K)
10.16.9 Amendment dated January 31, 1977. (Exhibit C-73, 1981 Form 10-K)
10.16.10 Amendment dated July 1, 1977. (Exhibit C-74, 1981 Form 10-K)
10.16.11 Amendment dated August 1, 1977. (Exhibit C-75, 1981 Form 10-K)
10.16.12 Amendment dated August 15, 1978. (Exhibit C-76, 1981 Form 10-K)
10.16.13 Amendment dated January 31, 1980. (Exhibit C-77, 1981 Form 10-K)
10.16.14 Amendment dated February 1, 1980. (Exhibit C-78, 1981 Form 10-K)
10.16.15 Amendment dated September 1, 1981. (Exhibit C-79 1981 Form 10-K)
10.16.16 Amendment dated December 1, 1981. (Exhibit C-80 1981 Form 10-K)
10.16.17 Amendment dated June 15, 1983. (Exhibit C-105, 1983 Form 10-K)
10.16.18 Amendment dated September 1, 1985. (Exhibit 10-160, 1986 Form 10-K)
10.16.19 Amendment dated April 30, 1987. (Exhibit 10-172, 1987 Form 10-K)
10.16.20 Amendment dated March 1, 1988. (Exhibit 10-178, 1988
 Form 10-K)
10.16.21 Amendment dated March 15, 1989. (Exhibit 10-194, 1989 Form 10-K)
10.16.22 Amendment dated October 1, 1990. (Exhibit 10-203, 1990 Form 10-K)
10.16.23 Amendment dated September 15, 1992. (Exhibit 10.16.23, 1992 Form 10-K)
10.16.24 Amendment dated May 1, 1993
10.16.25 Amendment dated June 1, 1993
10.17 Agreement dated October 13, 1972, for Joint Ownership, Construction and Operation of Pilgrim Unit No. 2 among Boston Edison Company and other utilities, including the Company. (Exhibit C-23, File No. 2-45990)
10.17.1 Amendments dated September 20, 1973, and September 15, 1974. (Exhibit C-24, File No. 2-51999)
10.17.2 Amendment dated December 1, 1974. (Exhibit C-25, File No. 2-54449)
10.17.3 Amendent dated February 15, 1975., (Exhibit C-26, File No. 2-53819)
10.17.4 Amendment dated April 30, 1975. (Exhibit C-27, File No. 2-53819)
10.17.5 Amendment dated as of June 30, 1975. (Exhibit C-28, File No. 2-54449)
10.17.6 Instrument of Transfer dated as of October 1, 1974, assigning partial interest from the Company to Green Mountain Power Corporation. (Exhibit C-29, File No. 2-52177)
10.17.7 Instrument of Transfer dated as of January 17, 1975, assigning a partial interest from the Company to the Burlington Electric Department. (Exhibit C-30, File No. 2-55458)
10.17.8 Addendum dated as of October 1, 1974 by which Green Mountain Power Corporation became a party thereto. (Exhibit C-31, File No. 2-52177)
10.17.9 Addendum dated as of January 17, 1975 by which the Burlington Electric Department became a party thereto. (Ehibit C-32, File No. 2-55450)
10.17.10 Amendment 23 dated as of 1975. (Exhibit C-50, 1975 Form 10-K)
10.18 Agreement for Sharing Costs Associated with Pilgrim Unit No.2 Transmission dated October 13, 1972, among Boston Edison Company and other utilities including the Company. (Exhibit C-33, File No. 2-45990)
10.18.1 Addendum dated as of October 1, 1974, by which Green
 Mountain Power Corporation became a party thereto. (Exhibit C-34, File No. 2-52177)
10.18.2 Addendum dated as of January 17, 1975, by which Burlington Electric Department became a party thereto. (Exhibit C-35, File No. 2-55458)
10.19 Agreement dated as of May 1, 1973, for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units among Public Service Company of New Hampshire and other utilities, including Velco. (Exhibit C-36, File No. 2-48966)
10.19.1 Amendments dated May 24, 1974, June 21, 1974, September 25, 1974, October 25, l974, and January 31, 1975. (Exhibit C-37, File No. 2-53674)
10.19.2 Instrument of Transfer dated September 27, 1974, assigning partial interest from Velco to the Company. (Exhibit C-38, File No. 2-52177)
10.19.3 Amendments dated May 24, 1974, June 21, 1974, and September 25, 1974. (Exhibit C-81, File No. 2-51999)
10.19.4 Amendments dated October 25, 1974 and January 31, 1975. (Exhibit C-82, File No. 2-54646)
10.19.5 Sixth Amendment dated as of April 18, 1979. (Exhibit C-83, File No. 2-64294)
10.19.6 Seventh Amendment dated as of April 18, 1979. (Exhibit C-84, File No. 2-64294)
10.19.7 Eighth Amendment dated as of April 25, 1979. (Exhibit C-85, File No. 2-64815)
10.19.8 Ninth Amendment dated as of June 8, 1979. (Exhibit C-86, File No. 2-64815)
10.19.9 Tenth Amendment dated as of October 10, 1979. (Exhibit C-87, File No. 2-66334 )
10.19.10 Eleventh Amendment dated as of December 15, 1979. (Exhibit C-88, File No.2-66492)
10.19.11 Twelfth Amendment dated as of June 16, 1980. (C-89, File No. 2-68168)
10.19.12 Thirteenth Amendment dated as of December 31, 1980. (Exhibit C-90, File No. 2-70579)
10.19.13 Fourteenth Amendment dated as of June 1, 1982.(Exhibit C-104, 1982 Form 10-K)
10.19.14 Fifteenth Amendment dated April 27, 1984. (Exhibit 10-134, 1986 Form 10-K)
10.19.15 Sixteenth Amendment dated June 15, 1984. (Exhibit 10-135, 1986 Form 10-K)
 10.19.16 Seventeenth Amendment dated March 8, 1985. (Exhibit 10-136, 1986 Form 10-K)
10.19.17 Eighteenth Amendment dated March 14, 1986. (Exhibit 10-137, 1986 Form 10-K)
10.19.18 Nineteenth Amendment dated May 1, 1986. (Exhibit 10-138, 1986 Form 10-K)
10.19.19 Twentieth Amendment dated September 19, 1986. (Exhibit 10-139, 1986 Form 10-K)
10.19.20 Amendment No. 22 dated January 13, 1989. (Exhibit 10-193, 1989 Form 10-K)
10.20 Transmission Support Agreement dated as of May 1, 1973, among Public Service Company of New Hampshire and other utilities, including Velco, with respect to New Hampshire Nuclear Units. (Exhibit C-39, File No. 248966)
10.21 Sharing Agreement - 1979 Connecticut Nuclear Unit dated September 1, 1973, to which the Company is a party. (Exhibit C-40, File No. 2-50142)
10.21.1 Amendment dated as of August 1, 1974. (Exhibit C-41, File No. 2-51999)
10.21.2 Instrument of Transfer dated as of February 28, 1974, transferring partial interest from the Company to Green Mountain. (Exhibit C-42, File No. 2-52177)
10.21.3 Instrument of Transfer dated January 17, 1975, transferring a partial interest from the Company to Burlington Electric Department. (Exhibit C-43, File No. 2-55458)
10.21.4 Amendment dated May 11, 1984. (Exhibit C-110, 1984 Form 10-K)
10.22 Preliminary Agreement dated as of July 5, 1974, with respect to 1981 Montague Nuclear Generating Units. (Exhibit C-44, File No. 2-51733)
10.22.1 Amendment dated June 30, 1975. (Exhibit C-45, File No. 2-54449)
10.23 Agreement for Joint Ownership, Construction and Operation of William F. Wyman Unit No. 4 dated November 1, 1974, among Central Maine Power Company and other utilities including the Company. (Exhibit C-46, File No. 2-52900)
10.23.1 Amendment dated as of June 30, 1975. (Exhibit C-47, File No. 2-55458)
10.23.2 Instrument of Transfer dated July 30, 1975, assigning a partial interest from Velco to the Company. (Exhibit C-48, File No. 2-55458)
 10.24 Transmission Agreement dated November 1, 1974, among Central Maine Power Company and other utilities including the Company with respect to William F. Wyman Unit No. 4. (Exhibit C-49, File No. 2-54449)
10.25 Copy of Power Contract between the Company and Yankee Atomic dated as of June 30, 1959. (Exhibit C-61, 1981 Form 10-K)
10.25.1 Revision dated April 1, 1975. (Exhibit C-61, 1981 Form 10-K)
10.25.2 Amendment dated May 6, 1988. (Exhibit 10-181, 1988 Form 10-K)
10.25.3 Amendment dated June 26, 1989. (Exhibit 10-196, 1989 Form 10-K)
10.25.4 Amendment dated July 1, 1989. (Exhibit 10-197, 1989 Form 10-K)
10.25.5 Amendment dated February 1, 1992 (Exhibit 10.25.5, 1992 Form 10-K)
10.26 Copy of Transmission Contract between the Company and Yankee Atomic dated as of June 30, 1959. (Exhibit C-63, 1981 Form 10-K)
10.27 Copy of Power Contract between the Company and Connecticut Yankee dated as of June 1, 1964. (Exhibit C-64, 1981 Form 10-K)
10.27.1 Supplementary Power Contract dated March 1, 1978. (Exhibit C-94, 1982 Form 10-K)
10.27.2 Amendment dated August 22, 1980. (Exhibit C-95 1982 Form 10-K)
10.27.3 Amendment dated October 15, 1982. (Exhibit C-96, 1982 Form 10-K)
10.27.4 Second Supplementary Power Contract dated April 30, 1984. (Exhibit C-115, 1984 Form 10-K)
10.27.5 Additional Power Contract dated April 30, 1984. (Exhibit C-116, 1984 Form 10-K)
10.28 Copy of Transmission Contract between the Company and Connecticut Yankee dated as of July 1, 1964. (Exhibit C-65 1981 Form 10-K)
10.29 Copy of Capital Funds Agreement between the Company and Connecticut Yankee dated as of July 1, 1964. (Exhibit C-66, 1981 Form 10-K)
10.29.1 Copy of Capital Funds Agreement between the Company and Connecticut Yankee dated as of September 1, 1964. (Exhibit C-67, 1981 Form 10-K)
 10.30 Copy of Five-Year Capital Contribution Agreement between the Company and Connecticut Yankee dated as of November 1, 1980. (Exhibit C-68, 1981 Form 10-K)
10.31 Form of Guarantee Agreement dated as of November 7, 1981, among certain banks, Connecticut Yankee and the Company, relating to revolving credit notes of Connecticut Yankee. (Exhibit C-69, 1981 Form 10-K)
10.32 Form of Guarantee Agreement dated as of November 13, 1981, between The Connecticut Bank and Trust Company, as Trustee, and the Company, relating to debentures of Connecticut Yankee. (Exhibit C-70, 1981 Form 10-K)
10.33 Form of Guarantee Agreement dated as of November 5, 1981, between Bankers Trust Company, as Trustee of the Vernon Energy Trust, and the Company, relating to Vermont Yankee Nuclear Fuel Sale Agreement. (Exhibit C-71, 1981 Form 10-K)
10.34 Preliminary Vermont Support Agreement re Quebec Interconnection between Velco and among seventeen Vermont Utilities dated May 1, 1981. (Exhibit C-97, 1982 Form 10-K)
10.34.1 Amendment dated June 1, 1982. (Exhibit C-98, 1982 Form 10-K)
10.35 Vermont Participation Agreement for Quebec Interconnection between Velco and among seventeen Vermont Utilities dated July 15, 1982. (Exhibit C-99, 1982 Form 10-K)
10.35.1 Amendment No. 1 dated January 1, 1986. (Exhibit C-132, 1986 Form 10-K)
10.36 Vermont Electric Transmission Company Capital Funds Support Agreement between Velco and among sixteen Vermont Utilities dated July 15, 1982. (Exhibit C-100, 1982 Form 10-K)
10.37 Vermont Transmission Line Support Agreement, Vermont Electric Transmission Company and twenty New England Utilities dated December 1, 1981, as amended by Amendment No. 1 dated June 1, 1982, and by Amendment No. 2 dated November 1, 1982. (Exhibit C-101, 1982 Form 10-K)
10.37.1 Amendment No. 3 dated January 1, 1986. (Exhibit 10-149, 1986 Form 10-K)
10.38 Phase 1 Terminal Facility Support Agreement between New England Electric Transmission Corporation and twenty New England Utilities dated December 1, 1981, as amended by Amendment No. 1 dated as of June 1, 1982 and by Amendment No. 2 dated as of November 1, 1982. (Exhibit C-102, 1982 Form 10-K)
10.39 Power Purchase Agreement between Velco and CVPS dated June 1, 1981. (Exhibit C-103, 1982 Form 10-K)
10.40 Agreement for Joint Ownership, Construction and Operation of the Joseph C. McNeil Generating Station by and between City of Burlington Electric Department, Central Vermont Realty, Inc.
 and Vermont Public Power Supply Authority dated May 14, 1982. (Exhibit C-107, 1983 Form 10-K
10.40.1 Amendment No. 1 dated October 5, 1982. (Exhibit C-108, 1983 Form 10-K)
10.40.2 Amendment No. 2 dated December 30, 1983. (Exhibit C-109, 1983 Form 10-K)
10.40.3 Amendment No. 3 dated January 10, 1984. (Exhibit 10-143, 1986 Form 10-K)
10.41 Transmission Service Contract between Central Vermont Public Service Corporation and The Vermont Electric Generation & Transmission Cooperative, Inc. dated May 14, 1984. (Exhibit C-111, 1984 Form 10-K)
10.42 Copy of Highgate Transmission Interconnection Preliminary Support Agreement dated April 9, 1984. (Exhibit C-117, 1984 Form 10-K)
10.43 Copy of Allocation Contract for Hydro-Quebec Firm Power dated July 25, 1984. (Exhibit C-118, 1984 Form 10-K)
10.43.1 Tertiary Energy for Testing of the Highgate HVDC Station Agreement, dated September 20, 1985. (Exhibit C-129, 1985 Form 10-K)
10.44 Copy of Highgate Operating and Management Agreement dated August 1, 1984. (Exhibit C-119, 1986 Form 10-K)
10.44.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-152, 1986 Form 10-K)
10.44.2 Amendment No. 2 dated November 13, 1986. (Exhibit 10-167, 1987 Form 10-K)
10.44.3 Amendment No. 3 dated January 1, 1987. (Exhibit 10-168, 1987 Form 10-K)
10.45 Copy of Highgate Construction Agreement dated August 1, 1984. (Exhibit C-120, 1984 Form 10-K)
10.45.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-151, 1986 Form 10-K)
10.46 Copy of Agreement for Joint Ownership, Construction and Operation of the Highgate Transmission Interconnection. (Exhibit C-121, 1984 Form 10-K)
10.46.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-153, 1986 Form 10-K)
10.46.2 Amendment No. 2 dated April 18, 1985. (Exhibit 10-154, 1986 Form 10-K)
10.46.3 Amendment No. 3 dated February 12, 1986. (Exhibit 10-155, 1986 Form 10-K)
 10.46.4 Amendment No. 4 dated November 13, 1986. (Exhibit 10-169, 1987 Form 10-K)
10.46.5 Amendment No. 5 and Restatement of Agreement dated January 1, 1987. (Exhibit 10-170, 1987 Form 10-K)
10.47 Copy of the Highgate Transmission Agreement dated August 1, 1984. (Exhibit C-122, 1984 Form 10-K)
10.48 Copy of Preliminary Vermont Support Agreement Re: Quebec Interconnection - Phase II dated September 1, 1984. (Exhibit C-124, 1984 Form 10-K)
10.48.1 First Amendment dated March 1, 1985. (Exhibit C-127, 1985 Form 10-K)
10.49 Vermont Transmission and Interconnection Agreement between New England Power Company and Central Vermont Public Service Corporation and Green Mountain Power Corporation with the consent of Vermont Electric Power Company, Inc., dated May 1, 1985. (Exhibit C-128, 1985 Form 10-K)
10.50 Service Contract Agreement between the Company and the State of Vermont for distribution and sale of energy from St. Lawrence power projects ("NYPA Power") dated as of June 25, 1985. (Exhibit C-130, 1985 Form 10-K)
10.50.1 Lease and Operating Agreement between the Company and the State of Vermont dated as of June 25, 1985. (Exhibit C-131, 1985 Form 10-K)
10.51 System Sales & Exchange Agreement Between Niagara Mohawk Power Corporation and Central Vermont Public Service Corporation dated October 1, 1986. (Exhibit C-133, 1986 Form 10-K)
10.52 Agreement of Purchase & Sale of 1.59096% Seabrook Ownership between Central Vermont Public Service Corporation and Eastern Utilities Associates dated February 19, 1986. (Exhibit 10-140, 1986 Form 10-K)
10.52.1 Addendum dated June 27, 1986. (Exhibit 10-141, 1986 Form 10-K)
10.53 Agreement between Bangor Hydro-Electric Company, Central Maine Power Company, Central Vermont Public Service Corporation, Fitchburg Gas and Electric Light Company, Maine Public Service Company and EUA Power Corporation dated October 20, 1986 conveying interests in transmission project facilities related to Seabrook. (Exhibit 10-142, 1986 Form 10-K)
10.54 Transmission Agreement between Vermont Electric Power Company, Inc. and Central Vermont Public Service Corporation dated January 1, 1986. (Exhibit 10-146, 1986 Form 10-K)
10.55 1985 Four Party Agreement between Vermont Electric Power Company, Central Vermont Public Service Corporation, Green Mountain Power Corporation and Citizens Utilities dated July 1, 1985. (Exhibit 10-146, 1986 Form 10-K)
 10.55.1 Amendment dated February 1, 1987. (Exhibit 10-171, 1987 Form 10-K)
10.56 1985 Option Agreement between Vermont Electric Power Company, Central Vermont Public Service Corporation, Green Mountain Power Corporation and Citizens Utilities dated December 27, 1985. (Exhibit 10-148, 1986 Form 10-K)
10.56.1 Amendment No. 1 dated September 28, 1988. (Exhibit 10-182, 1988 Form 10-K)
10.56.2 Amendment No. 2 dated October 1, 1991. (Exhibit 10.56.2, 1991 Form 10-K)
10.57 Highgate Transmission Agreement dated August 1, 1984 by and between the owners of the project and the Vermont electric distribution companies. (Exhibit 10-156, 1986 Form 10-K)
10.57.1 Amendment No. 1 dated September 22, 1985. (Exhibit 10-157, 1986 Form 10-K)
10.58 Vermont Support Agency Agreement re: Quebec Interconnection - Phase II between Vermont Electric Power Company, Inc. and participating Vermont electric utilities dated June 1, 1985. (Exhibit 10-158, 1986 Form 10K)
10.58.1 Amendment No. 1 dated June 20, 1986. (Exhibit 10-159, 1986 Form 10-K)
10.59 Indemnity Agreement B-39 dated May 9, 1969 with amendments 1-16 dated April 17, 1970 thru April 16, 1985 between licensees of Millstone Unit No. 3 and the Nuclear Regulatory Commission. (Exhibit 10-161, 1986 Form 10-K)
10.59.1 Amendment No. 17 dated November 25, 1985. (Exhibit 10-162, 1986 Form 10-K)
10.60 Memorandum of Understanding by and between The Champlain Pipeline Company and Northern New England Gas Corporation, Noverco Corporation and Central Vermont Equity Corporation dated February 2, 1987. (Exhibit 10-163, 1987 Form 10-K)
10.60.1 Amendment No. 1 dated April 10, 1987. (Exhibit 10-164, 1987 Form 10-K)
10.60.2 Assignment Agreement by and between CV Energy Resources, Inc. and CV Champlain Investments, Inc. dated December 31, 1987. (Exhibit 10-165, 1987)
10.61 General Partnership Agreement re: Champlain Pipeline Partnership dated January 1, 1988 by and between Noverco, Northern New England Gas Corporation, CV Energy Resources, Inc. and Providence Energy Corporation. (Exhibit 10-166, 1987 Form 10-K)
10.62 Contract for the Sale of 50MW of firm power between Hydro-Quebec and Vermont Joint Owners of Highgate Facilities dated February 23, 1987. (Exhibit 10-173, 1987 Form 10-K)
 10.63 Interconnection Agreement between Hydro-Quebec and Vermont Joint Owners of Highgate facilities dated February 23, 1987. (Exhibit 10-174, 1987 Form 10-K)
* 10.63.1 Amendment dated September 1, 1993 (Exhibit 10.63.1, 1993 Form 10-K)
10.64 Firm Power and Energy Contract by and between Hydro-Quebec and Vermont Joint Owners of Highgate for 500MW dated December 4, 1987. (Exhibit 10-175, 1987 Form 10-K)
10.64.1 Amendment No. 1 dated August 31, 1988. (Exhibit 10-191, 1988 Form 10-K)
10.64.2 Amendment No. 2 dated September 19, 1990. (Exhibit 10-202, 1990 Form 10-K)
10.64.3 Firm Power & Energy Contract dated January 21, 1993 by and between Hydro-Quebec and Central Vermont Public Service Corporation for the sale back of 25 MW of power. (Exhibit 10.64.3, 1992 Form 10-K)
10.64.4 Firm Power & Energy Contract dated January 21, 1993 by and between Hydro-Quebec and Central Vermont Public Service Corporation for the sale back of 50 MW of power. (Exhibit 10.64.4, 1992 Form 10-K)
10.65 Settlement Agreement between EUA Power Corporation, Bangor Hydro-Electric Company, Central Maine Power Company, Central Vermont Public Service Corporation and Maine Public Service Company dated January 31, 1988 re: Seabrook real estate. (Exhibit 10-176, 1988 Form 10-K)
10.66 Hydro-Quebec Participation Agreement dated April 1, 1988 for 600 MW between Hydro-Quebec and Vermont Joint Owners of Highgate. (Exhibit 10-177, 1988 Form 10-K)
10.67 Sale of firm power and energy (54MW) between Hydro-Quebec and Vermont Utilities dated December 29, 1988. (Exhibit 10-183, 1988 Form 10-K)
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
10.68 Stock Option Plan for Non-Employee Directors dated July 18, 1988. (Exhibit 10-184, 1988 Form 10-K)
10.69 Stock Option Plan for Key Employees dated July 18, 1988. (Exhibit 10-185, 1988 Form 10-K)
10.70 Officers Supplemental Insurance Plan authorized July 9, 1984. (Exhibit 10-186, 1988 Form 10-K)
10.71 Officers Supplemental Deferred Compensation Plan dated November 4, 1985. (Exhibit 10-187, 1988 Form 10-K)
10.72 Directors' Supplemental Deferred Compensation Plan dated November 4, 1985. (Exhibit 10-188, 1988 Form 10-K)
 10.73 Management Incentive Compensation Plan as adopted September 9, 1985. (Exhibit 10-189, 1988 Form 10-K)
10.73.1 Revised Management Incentive Plan as adopted February 5, 1990. (Exhibit 10-200. 1989 Form 10-K)
10.74 Officers' Change of Control Agreements as approved October 3, 1988. (Exhibit 10-190, 1988 Form 10-K)
* 10.78 Stock Option Plan for Non-Employee Directors dated April 30, 1993 (Exhibit 10.78, 1993 Form 10-K)
* 10.79 Officers Insurance Plan dated November 15, 1993 (Exhibit 10.79, 1993 Form 10-K)
* 10.80 Directors'Supplemental Deferred Compensation Plan dated (Exhibit 10.80, 1993 Form 10-K)
* 10.81 Officers' Supplemental Deferred Compensation Plan dated (Exhibit 10.81, 1993 Form 10-K)
-------------------------------------------- 10.75 Receivables Purchase Agreement between Central Vermont Public Service Corporation, Central Vermont Public Service Corporation as Service Agent and The First National Bank of Boston dated November 29, 1988. (Exhibit 10-192, 1988 Form 10-K)
* 10.75.1 Agreement Amendment No. 1 dated December 21, 1988 (Exhibit 10.75.1, 1993 Form 10-K)
* 10.75.2 Letter Agreement dated December 4, 1989 (Exhibit 10.75.2, 1993 Form 10-K)
* 10.75.3 Agreement Amendment No. 2 dated November 29, 1990 (Exhibit 10.75.3, 1993 Form 10-K)
* 10.75.4 Agreement Amendment No. 3 dated November 29, 1991 (Exhibit 10.75.4, 1993 Form 10-K)
* 10.75.5 Agreement Amendment No. 4 dated November 29, 1992 (Exhibit 10.75.5, 1993 Form 10-K)
10.76 Power Purchase Agreement with Bonneville Pacific Corporation, Unit I, dated November 15, 1989. (Exhibit 10-198, 1989 Form 10-K)
10.77 Power Purchase Agreement with Bonneville Pacific Corporation, Unit II, dated November 15, 1989. (Exhibit 10-199, 1989 Form 10-K)
* 10.82 Transmission Service Agreement between this Company and Green Mountain Power Corporation dated September 1, 1993 (Exhibit 10.82, 1993 Form 10-K)
11. Not applicable.
12. Not applicable.
13. 1992 Annual Report to Stockholders
* 13.1 Portions of the Annual Report to Stockholders of Central Vermont Public Service Corporation that have been incorporated by reference under Items 6, 7 and 8
16. Change in certifying accountant (July 1, 1985 Form 8-K)
18. Letter re change in accounting principles (1980 3rd Quarter Form 10-Q)
21. Subsidiaries of the Registrant
* 21.1 List of subsidiaries of registrant
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
By /s/ Thomas C. Webb Thomas C. Webb, President and Chief Executive Officer
By /s/ Robert H. Young Robert H. Young, Executive Vice President - Chief Operating Officer and Principal Financial Officer
By /s/ James M. Pennington James M. Pennington, Controller and Principal Accounting Officer
March 14, 1994
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
March 14, 1994 /s/ Frederic H. Bertrand Frederic H. Bertrand Director
March 14, 1994 /s/ Robert P. Bliss, Jr. Robert P. Bliss, Jr. Director
March 14, 1994 /s/ Elizabeth Coleman Elizabeth Coleman Director
March 14, 1994 /s/ Luther F. Hackett Luther F. Hackett Director
March 14, 1994 /s/ F. Ray Keyser, Jr. F. Ray Keyser, Jr. Director
March 14, 1994 /s/ Mary Alice McKenzie Mary Alice McKenzie Director
March 14, 1994 /s/ Gordon P. Mills Gordon P. Mills Director
March 14, 1994 /s/ Preston Leete Smith Preston Leete Smith Director
March 14, 1994 /s/ Robert D. Stout Robert D. Stout Director
March 14, 1994 /s/ Thomas C. Webb Thomas C. Webb Director
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
Annual Report Pursuant to Section 13 of 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended Commission File No. 1-8222 December 31, 1993
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
EXHIBITS
TO
1993 FORM 10-K
INDEX
List of Exhibits
1993 Form 10-K
4-53 Copy of Thirty-Eight Supplemental Indenture dated December 10, 1993 establishing Series KK, LL, MM, NN, OO supplemental to B-1
10.16.24 Amendment dated May 1, 1993.
10.16.25 Amendment dated June 1, 1993
10.63.1 Amendment dated September 1, 1993
10.75.1 Agreement Amendment No. 1 dated December 21, 1988
10.75.2 Letter Agreement dated December 4, 1989
10.75.3 Agreement Amendment No. 2 dated November 29, 1990
10.75.4 Agreement Amendment No. 3 dated November 29, 1991
10.75.5 Agreement Amendment No. 4 dated November 29, 1992
10.78 Stock Option Plan for Non-Employee Directors dated April 30,
10.79 Officers Insurance Plan dated November 15, 1993
10.80 Directors'Supplemental Deferred Compensation Plan dated January 1, 1990
10.81 Officers' Supplemental Deferred Compensation Plan dated January 1, 1990
10.82 Transmission Service Agreement between this Company and Green Mountain Power Corporation dated September 1, 1993
13 Annual Report to Security holders
13.1 Portions of the Annual Report to Stockholders of Central Vermont Public Service Corporation that have been incorporated by reference under Items 6, 7 and 8
18. Letter re change in accounting principles (1980 3rd Quarter Form 10-Q)
21. Subsidiaries of the Registrant
* 21.1 List of subsidiaries of registrant