Annual Report (Form 10-K), fiscal year 1994

Item 1. Business.
Overview.
Central Vermont Public Service Corporation (the "Company"), incorporated under the laws of Vermont on August 20, 1929, is engaged in the purchase, production, transmission, distribution and sale of electricity. The Company has various wholly and partially owned subsidiaries. These subsidiaries are described below.
The Company is the largest electric utility in Vermont and serves 135,704 customers in 175 of the 245 towns in Vermont. This represents about 50% of the Vermont population. In addition, the Company supplies electricity at wholesale to one municipal, one rural cooperative, and one private utility.
The Company's sales are derived from a diversified customer mix. The Company's sales to residential, commercial and industrial customers accounted for 56% of total MWH sales for the year 1994. Sales to the five largest retail customers receiving electric service from the Company during the same period constituted about 4.7% of the Company's total electric revenues for the year. The Company's requirements resale sales accounted for approximately 4%, entitlement sales accounted for 23% and other resale sales which include contract sales, opportunity sales and sales to NEPOOL accounted for approximately 17% of total MWH sales for the year 1994.
Connecticut Valley Electric Company Inc. ("Connecticut Valley"), a wholly owned subsidiary of the Company, incorporated under the laws of New Hampshire on December 9, 1948, distributes and sells electricity in parts of New Hampshire bordering the Connecticut River. It serves 10,261 customers in 13 communities in New Hampshire. About 2% of the New Hampshire population resides in its service area. Connecticut Valley's sales are also derived from a diversified customer mix. Connecticut Valley's sales to residential, commercial and industrial customers accounted for 99.5% of total MWH sales for the year 1994. Sales to its five largest retail customers during the same period equaled about 17.9% of Connecticut Valley's total electric revenues for the year.
The Company also owns 56.8% of the common stock and 46.6% of the preferred stock of Vermont Electric Power Company, Inc. ("VELCO"). VELCO owns the high voltage transmission system in Vermont. VELCO created a wholly owned subsidiary, Vermont Electric Transmission Company, Inc. ("VETCO"), to finance, construct and operate the Vermont portion of the 450 KV DC transmission line connecting Quebec with Vermont and New England. In addition, the Company owns 31.3% of the common stock of Vermont Yankee Nuclear Power Corporation ("Vermont Yankee"), a nuclear generating company. The Company also owns 2% of the outstanding common stock of Maine Yankee Atomic Power Company, 2% of the outstanding common stock of Connecticut Yankee Atomic Power Company and 3.5% of the outstanding common stock of Yankee Atomic Electric Company.
The Company has two wholly owned subsidiaries that were created for the purpose of financing and constructing two hydroelectric facilities in Vermont: Central Vermont Public Service Corporation - Bradford Hydroelectric, Inc. ("Bradford"), which became operational December 20, 1982, and Central Vermont Public Service Corporation - East Barnet Hydroelectric, Inc. ("East Barnet"), which became operational September 1, 1984. These hydro electric facilities have been leased and operated by the Company since their respective in- service dates. The Company also has the following wholly owned non-utility subsidiaries: C.V. Realty Inc., a real estate company, Catamount Energy Corporation whose primary purpose is to invest in non-regulated, energy-supply projects, CV Energy Resources, Inc. whose primary purpose is to invest in non- regulated energy-related projects and SmartEnergy Services, Inc. whose purpose is to cost effectively provide reliable energy efficient products and services, including the rental of electric water heaters.
Catamount Energy Corporation currently has four wholly owned subsidiaries: (See "DIVERSIFICATION"); Catamount Rumford Corp., Equinox Vermont Corporation, Appomattox Vermont Corp. and Catamount Williams Lake L.P. For additional information of the Company's diversification activities, see Item 8 herein.
REGULATION AND COMPETITION
State Commissions.
The Company is subject to the regulatory authority of the Vermont Public Service Board ("PSB") with respect to rates, and the Company and VELCO are subject to PSB jurisdiction respecting securities issues, construction of major generation and transmission facilities and various other matters. The Company is subject to the regulatory authority of the New Hampshire Public Utilities Commission as to matters pertaining to construction and transfers of utility property in New Hampshire. Additionally, the Public Utilities Commission of Maine and the Connecticut Department of Public Utility Control exercise limited jurisdiction over the Company based on its ownership as a tenant-in-common of Wyman #4 and Millstone #3, respectively.
Connecticut Valley is subject to the regulatory authority of the New Hampshire Public Utilities Commission ("NHPUC") with respect to rates, securities issues and various other matters.
Federal Power Act.
Certain phases of the businesses of the Company and VELCO, including certain rates, are subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC"): the Company as a licensee of hydroelectric developments under Part I, and the Company and VELCO as interstate public utilities under Parts II and III, of the Federal Power Act, as amended and supplemented by the National Energy Act.
The Company has licenses expiring at various times under Part I of the Federal Power Act for twelve of its hydroelectric plants. The Company has obtained an exemption from licensing for the Bradford and East Barnet projects.
Public Utility Holding Company Act of 1935.
Although the Company, by reason of its ownership of utility subsidiaries, is a holding company, as defined in the Public Utility Holding Company Act of 1935, it is presently exempt, pursuant to Rule 2, promulgated by the Commission under said Act, from all the provisions of said Act except Section 9(a)(2) thereof relating to the acquisition of securities of public utility affiliates.
Environmental Matters.
In recent years, public concern for the physical environment has resulted in increased governmental regulation of environmental matters. The Company is subject to these regulations in the licensing and operation of the generation, transmission, and distribution facilities in which it has interest, as well as the licensing and operations of the facilities in which it is a co-licensee. These environmental regulations are administered by local, state and Federal regulatory authorities and concern the impact of the Company's generation, transmission, distribution, transportation and waste handling facilities on air, water, land and aesthetic qualities.
The Company cannot presently forecast the costs or other effects which environmental regulation may ultimately have upon its existing and proposed facilities and operations, because the extent of the applicability is not known at this time. The Company believes that any such costs related to its utility operations would be recoverable through the rate-making process. For additional information see Item 7 herein and refer to Item 8 herein for disclosures relating to environmental contingencies, hazardous substance releases and the control measures related thereto.
Nuclear Matters.
The nuclear generating facilities of Vermont Yankee and the other nuclear facilities in which the Company has an interest are subject to extensive regulations by the Nuclear Regulatory Commission ("NRC"). The NRC is empowered to regulate the siting, construction and operation of nuclear reactors with respect to public health, safety, environmental and antitrust matters. Under its continuing jurisdiction, the NRC may, after appropriate proceedings, require modification of units for which operating licenses have already been issued, or impose new conditions on such licenses, and may require that the operation of a unit cease or that the level of operation of a unit be temporarily or permanently reduced. Refer to Item 8 herein for disclosures relating to the shut down of the Yankee Atomic Nuclear Power plant.
Competition.
Competition now takes several forms. At the wholesale level, where the utility-to-utility market has been highly competitive for years, independent companies now compete to be the low-cost providers of power to local and regional utilities. A growing competitive threat is rooted in the belief that lower priced electricity could be made available to residents and business by voters establishing a municipally owned utility. At the retail level, customers have long had energy options such as propane, natural gas or oil for heating, cooling and water heating, and self-generation for larger customers. Changes anticipated as a result of the National Energy Policy Act of 1992 and evolving state regulatory policy may even bring about direct utility-to- utility competition for these retail customers.
However, pursuant to Vermont statutes (30 V.S.A. Section 249), the PSB has established as the service area for the Company the area it now serves. Under 30 V.S.A. Section 251(b) no other company is legally entitled to serve any retail customers in the Company's established service area.
An amendment to 30 V.S.A. Section 212(a) enacted May 28, 1987 authorizes the Vermont Department of Public Service ("Department") to purchase and distribute power at retail to all customers of electricity in Vermont, subject to certain preconditions specified in new sections 212(b) and 212(c). Section 212(b) provides that a review board consisting of the Governor and certain other designated legislative officers review and approve any retail proposal by the Department if they are satisfied that the benefits outweigh any potential risk to the State. However, the Department may proceed to file the retail proposal with the PSB either upon approval by the review board or the failure of the board to act within sixty (60) days of the submission. Section 212(c) provides that the Department shall not enter into any retail sales arrangement before the PSB determines and approves certain findings. Those findings are (1) the need for the sale, (2) the rates are just and reasonable, (3) the sale will result in economic benefit, (4) the sale will not adversely affect system stability and reliability and (5) the sale will be in the best interest of ratepayers.
Section 212(d) provides that upon PSB approval of the Department retail sales proposal, Vermont utilities shall make arrangements for distributing such electricity on terms and conditions that are negotiated. Failing such negotiation, the PSB is directed to determine such terms as will compensate the utility for all costs reasonably and necessarily incurred to provide such arrangements. See Rate Developments below for additional details involving retail sales by the Department.
In addition, Chapter 79 of Title 30 authorizes municipalities to acquire the electric distribution facilities located within their boundaries. The exercise of such authority is conditioned upon an affirmative three-fifths vote of the legal voters in an election and upon the payment of just compensation including severance damages. Just compensation is determined either by negotiation between the municipality and the utility or, in the event the parties fail to reach an agreement, by the Public Service Board after a hearing. If either party is dissatisfied, the statute allows them to appeal the Board's determination to the Vermont Supreme Court. Once the price is determined, whether by agreement of the parties or by the PSB, a second affirmative three-fifths vote of the legal voters is required.
Competition in the energy services market exists between electricity and fossil fuels. In the residential and small commercial sectors this competition is primarily for electric space and water heating from propane and oil dealers. Competitive issues are price, service, convenience, cleanliness and safety.
In the large commercial and industrial sectors, cogeneration and self- generation are the major competitive threats to electric sales. Competitive risks in these market segments are primarily related to seasonal, one-shift operations that can tolerate periodic power outages, and for industrial customers with steady heat loads where the generator's waste heat can be used in their manufacturing process. Competitive advantages for electricity in those segments are the cost of back up power sources, space requirements, noise problems, and maintenance requirements.
There has been only one instance where Chapter 79 of Title 30 has been invoked; the Town of Springfield acted to acquire the Company's distribution facilities in that community pursuant to a vote in 1977. This action was subsequently discontinued by agreement between Springfield and the Company in 1985.
In addition, in late 1994 the Select Board of the Town of Bennington considered whether to publicly warn a vote to acquire the Company's facilities located in Bennington pursuant to Chapter 79 of Title 30. By vote of the Selectors taken on January 9, 1995, the Town decided not to pursue the vote and to discontinue further study of the creation of a municipal utility at this time.
No other municipality served by the Company, so far as is known to the Company, has taken any formal steps in an attempt to establish a municipal electric distribution system.
For a discussion relating to the Company's wholesale electric business see "Wholesale Rates" below.
RATE DEVELOPMENTS
Vermont Retail Rates.
In response to a March 1993 PSB inquiry into the appropriateness of a general review of the Company's retail rates, in April 1993 the DPS and the Company entered into a Stipulation that was approved by the PSB in September 1993. In the Stipulation the Company agreed to a decrease in its allowed rate of return on common equity from 12.5% to 12.0% for 1993, to accelerate the recovery of $1.5 million of Conservation and Load Management ("C&LM") costs deferred in 1993, to not seek recovery of further C&LM costs deferred in 1993 equal to amounts in excess of the 12.0% rate of return on common equity for 1993, and to not file a general rate increase that would become effective before August 1, 1994. The PSB in its September 1993 order also announced the opening of an investigation on November 16, 1993, the earliest date the Company could file for a rate increase under the Stipulation, into the Company's cost of service and resulting rates.
In response to that investigation, on January 18, 1994 the Company filed a revenue requirement supporting a $16.1 million or 8.0% increase in retail rates for the year beginning November 1, 1993. The Company noted in its filing that current rate levels are justified and that the Company does not want any rate increase to be effective for that period. The Company also noted in its filing that rate relief would be needed in late 1994.
Thus on February 15, 1994, the Company filed for a rate increase of $17.9 million or 8.9% to become effective November 1, 1994. The PSB consolidated its investigation and the Company's rate increase request. The PSB also broadened its investigation to specifically include the Company's management of its power contracts. During the hearings, the PSB approved a settlement of power costs between the DPS and the Company. The PSB's approval of such settlement specifically excluded the as yet unknown effects of the PSB's investigation of the Company's management of its power contracts.
By PSB order dated October 31, 1994 and revised PSB order dated December 14, 1994, the PSB ordered (1) no changes in rates pursuant to its investigation and (2) a $10.192 million or 5.07% rate increase effective November 1, 1994 pursuant to the Company's rate increase request. The 10.75% rate of return on common equity allowed by the PSB was reduced by a .75% penalty based on the PSB's conclusions that there had been "mismanagement of power supply options" and because of "the Company's failed efforts to acquire all cost-effective energy efficiency resources."
The Company anticipates filing for future rate increases when cost containment efforts are insufficient to offset the increasing cost of providing service, primarily purchased power.
New Hampshire Retail Rates.
Connecticut Valley's retail rate tariffs, approved by the NHPUC, contain a fuel adjustment clause (FAC) and a purchased power cost adjustment clause (PPCA). Under these clauses, Connecticut Valley recovers its estimated annual costs for purchased energy and capacity, respectively, which are reconciled when actual data is available. On the basis of estimates of costs for 1995 and reconciliations from 1994, the combined PPCA and FAC will result in a decrease in revenues of approximately $489,000 or 2.7% for 1995.
Connecticut Valley's retail rate tariffs, approved by the NHPUC, also provide for Conservation and Load Management Percentage Adjustments (C&LMPA) for residential and commercial/industrial customers in order to collect deferred and forecast C&LM costs. The forecast costs are updated effective January 1 of each year and are reconciled when actual data are available. In addition, Connecticut Valley's earnings are made whole through recovery of lost revenues related to fixed costs which Connecticut Valley loses as a result of C&LM activities. However, the Company is not made whole because the fixed costs of the wholesale transaction between the Company and Connecticut Valley are not recovered when C&LM activities occur in Connecticut Valley. The C&LMPA further provides for the future recovery of shareholder incentives related to past C&LM activities.
In October 1994 Connecticut Valley filed its annual update of the 1995 C&LMPA rates. When the schedule for hearings pointed to an effective date of April 1, 1995, Connecticut Valley petitioned to let revised C&LMPA rates become effective January 1, 1995. Such C&LMPA rates would be lower than they would be at the April 1 effective date. In addition, the January 1 effective date would coincide with the effective date of the FAC and PPCA so that one rate change would be experienced by the customers. Connecticut Valley also felt that further changes to the C&LMPA rates might not be necessary effective April 1, 1995 depending on the outcome of the hearings. The NHPUC allowed a $48,000 or 0.3% increase in the C&LMPA rates effective January 1, 1995.
Connecticut Valley also purchases power from several small power producers who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. In 1994, under long-term contracts with these qualifying facilities, Connecticut Valley purchased 4.3 MW, of which 3.9 MW were purchased from a New Hampshire/Vermont solid waste plant owned by Wheelabrator Claremont Company, L.P., (Wheelabrator). Connecticut Valley has filed a complaint with the Federal Energy Regulatory Commission (FERC) stating its concern that Wheelabrator has not been a qualifying facility since the plant began operation. Potential outcomes of this complaint could result in a refund, with interest, of past purchased power costs as well as lower future costs. Any refunds and lower future costs are likely to be reflected in the FAC. Pursuant to a Company request, the NHPUC issued an accounting order allowing deferral of litigation costs related to this FERC complaint, with recovery to be determined when the outcome of the FERC complaint is known and petitioned for implementation.
Wholesale Rates.
The Company sells firm power to Connecticut Valley under a wholesale rate schedule based on forecast data for each calendar year which is reconciled to actual data annually. The Company filed with the FERC for a revenue increase of $466,000 or 4.7% for 1995 power costs. The rate schedule provides for an automatic update of annual rates, as well as the subsequent reconciliation to actual data.
As ordered by the NHPUC in Connecticut Valley's 1994 C&LMPA docket, the Company entered into negotiations with the NHPUC Staff to redesign the RS-2 wholesale rate under which Connecticut Valley purchases power from the Company. The redesign features marginal cost based energy and capacity charges for all energy and capacity purchases above or below a base level. Such negotiations concluded at the end of 1994. A summary report was filed with the NHPUC on February 13, 1995. The NHPUC has yet to issue an order approving the summary report. Connecticut Valley's costs of wholesale power will be lower than they otherwise would be only if Connecticut Valley's growth rate exceeds that of the Company's Vermont retail operations.
Another of the Company's requirements wholesale customers, New Hampshire Electric Cooperative, Inc., with an average monthly peak of 2.8 MW has given the Company notice of termination of service under FERC Electric Tariff, First Revised Volume No. 1, effective in March 1995. The Company has entered into negotiations to provide transmission service and will submit a bid to supply power under another contract.
POWER RESOURCES
Overview.
The Company's and Connecticut Valley's energy production, which includes generated and purchased power, required to serve their retail and firm wholesale customers was 2,410,703 MWH for the year ended December 31, 1994. The maximum one-hour integrated demand during that period was 414.6 MW, which occurred on January 17, 1994. The Company's and Connecticut Valley's total production in 1994, including production related to all resale customers, was 3,926,382 MWH.
The following tabulation shows the sources of such energy and capacity available to the Company and Connecticut Valley for the year ended December 31, 1994 and at the time of the Company's own peak. For additional information related to purchased power costs, refer to Item 7 herein.
Wholly Owned Plants.
The Company owns and operates 18 hydroelectric generating facilities in Vermont which have an aggregate nameplate capability of 37.5 MW. It also leases and operates hydroelectric facilities at Bradford and East Barnet, Vermont. These two plants have a nameplate capability of 1.5 MW and 2.2 MW, respectively. In addition, the Company owns and operates diesel and gas turbine generating facilities on a peaking or standby basis having a combined nameplate capability of 28.9 MW.
Jointly Owned Plants.
The Company has a joint-ownership interest in the following generating and transmission plants:
The Company has a 1.73% joint-ownership interest in Millstone #3, an 1149 MW nuclear generating facility located in Waterford, Connecticut, which commenced commercial operation in April 1986. Under the Millstone Sharing Agreement, the Company is entitled to receive its share of the output and capacity of the facility and is responsible for its share of the operating expenses, including decommissioning. Based on a 1992 study, total estimated decommissioning obligation at December 31, 1994 was approximately $449 million and the funded obligation was about $76 million. The Company's share for the total obligation and funded obligation was approximately $7.8 million and $1.1 million, respectively.
The Company also has a 1.78% joint-ownership interest in Wyman #4, a 619 MW oil-fired generating facility located in Yarmouth, Maine and a 20% joint-ownership interest in McNeil, a 53 MW wood, gas and oil-fired generating facility located in Burlington, Vermont. The Company receives its share of the output and capacity from these generating plants and is responsible for its share of the operating expenses of each.
Finally the Company has a 46.08% joint-ownership interest in the Highgate Convertor, a 200 MW facility located in Highgate Springs, Vermont. This facility is directly connected to the Hydro-Quebec System to the north of the Convertor and to the VELCO System for delivery of power to Vermont Utilities. This facility can deliver power either direction, but normally delivers power from Hydro-Quebec to Vermont.
Equity Ownership in Plants.
In 1966 the Company purchased 35% of the Vermont Yankee common stock and was entitled to receive a like percentage of the output of the unit. In late 1969 and early 1970, the Company sold at cost a combined total of 3.7% of its original equity investment and currently resells at cost 4.5% of its entitlement. The Company's current equity ownership and net entitlement percentages are 31.3 and 30.5, respectively.
The Atomic Energy Commission, now the NRC, granted a full-term (40-year), full power operating license for the Vermont Yankee plant, which was to expire in December 2007. On December 17, 1990 the NRC issued an amendment of the operating license extending its term to March 2012.
Vermont Yankee's net capability is 514 MW of which 156.7 MW (See Note 1) is the Company's net entitlement. Vermont Yankee's plant performance for the past five years is shown below:
Availability Capacity Factor Factor (See Note 2) (See Note 3)
1990......................... 84.4 80.3 1991......................... 93.6 91.2 1992......................... 87.5 82.7 1993......................... 78.3 74.9 1994......................... 98.2 95.8
As described in the overview section above, the Company is a stockholder, together with other New England electric utilities, in the following three nuclear generating companies: Maine Yankee Atomic Power Company, Connecticut Yankee Atomic Power Company and Yankee Atomic Electric Company.
Net Company's Company Capability Entitlement
Maine Yankee (See Note 4)..... 847 MW 2.0% - 16.9 MW Connecticut Yankee............ 582 MW 2.0% - 11.6 MW Yankee Atomic................. (See Note 5) (See Note 5)
The Company is obligated to pay its entitlement percentage of the operating expenses of Vermont Yankee and the other Yankee companies, including depreciation and a return on invested capital, whether or not the plant is operating. The Company is obligated to contribute its entitlement percentage of the capital requirements of Vermont Yankee and Maine Yankee and has a similar, but more limited obligation to Connecticut Yankee. The Company's entitlement percentages are identical to the ownership percentages except that Vermont Yankee's entitlement percentage is 35%. For additional information regarding Equity Ownership in Plants, refer to Item 8 herein. _______________ Notes: (1) Currently, the Company resells at cost, through VELCO, 23.2 MW of its original entitlement to other Vermont utilities.
(2) "Availability Factor" means the hours that the plant is capable of producing electricity divided by the total hours in the period.
(3) "Capacity Factor" means the total net electrical generation divided by the product of the maximum design electrical rating capacity of 514 multiplied by the total hours in the period.
(4) Currently, the Company resells at cost 1.8 MW of its entitlement to certain municipal utilities in Massachusetts.
(5) Yankee Atomic permanently ceased power operations of the Yankee Nuclear Power Station. See Decommissioning Expense discussion below.
Decommissioning Expense.
Each of the Yankee companies and Millstone #3 has developed its own estimate of the cost of decommissioning its nuclear generating unit. These estimates vary depending upon the method of decommissioning, economic assumptions, site and unit specific variables, and other factors. Each of the Yankee Companies includes charges for decommissioning costs in the cost of capacity, as approved by the FERC. Decommissioning costs for Millstone #3 are included in depreciation expenses.
The Company's entitlement percentage of decommissioning costs for Vermont Yankee, Connecticut Yankee, Maine Yankee, Yankee Atomic and Millstone #3 is as follows (dollars in millions): CVPS's Total Share of Date of Estimated CVPS's Funded Study Obligation Obligation Obligation Nuclear generating companies: Vermont Yankee 1993 $312.7 $109.4 $40.3 Maine Yankee 1993 $316.6 $6.3 $2.2 Connecticut Yankee 1992 $294.2 $5.9 $3.0 Yankee Atomic 1994 $370 $13.0 $3.6 Millstone #3 1992 $449 $7.8 $1.1
On February 26, 1992, the Board of Directors of Yankee Atomic decided to permanently discontinue operation of their plant, and, to decommission the facility.
The Company relied on Yankee Atomic for less than 1.5% of its system capacity. Presently, purchased power costs billed to the Company by Yankee Atomic, which include a provision for ultimate decommissioning of the unit, are being collected from the Company's customers via existing retail rate tariffs.
On March 18, 1993, the FERC approved a settlement agreement regarding the decommissioning plan, recovery of plant investment and all issues with respect to prudency of the decision to discontinue operation which included $247 million of decommissioning costs in 1992 dollars. Based on a new study developed by Yankee Atomic, decommissioning costs are approximately $370 million in 1994 dollars. The increase results primarily from delays in finding a permanent repository for its spent nuclear fuel. The new study is subject to FERC approval. Yankee Atomic is currently collecting from sponsors decommissioning costs based on $247 million in 1992 dollars and anticipates to begin collecting from sponsors based on $370 million in November 1995. The Company's share of the increase in decommissioning costs is approximately $4.3 million.
The Company's total current share of its cost with respect to Yankee Atomic's decision to discontinue operation is approximately $12.4 million. This amount is reflected in the accompanying balance sheet both as a regulatory asset and deferred power contract obligation (current and non- current).
The Company believes that its proportionate share of Yankee Atomic costs will be recovered through the regulatory process and, therefore, the ultimate resolution of the premature retirement of the plant will not have a material adverse effect on the Company's earnings or financial condition.
Although the estimated costs of decommissioning are subject to change due to changing technologies and regulations, the Company expects that the nuclear generating companies' liability for decommissioning, including any future changes in the liability, will be recovered in their rates over their operating or license lives. See Item 8 herein.
In 1982 the State of Maine enacted legislation that requires the development of a decommissioning trust fund for the Maine Yankee nuclear plant. This statute also provides that, if the trust has insufficient funds to decommission the plant, the licensee, Maine Yankee, is responsible for the deficiency and, if the licensee is unable to provide the entire amount, the owners of the licensee are jointly and severally responsible for the remainder. The definition of owner under the statute includes the Company. It is expected that any payments required by the Company under these provisions would be recovered through rates.
Nuclear Fuel.
Vermont Yankee has approximately $133 million of "requirements based" purchase contracts for nuclear fuel needs to meet substantially all of its power production requirements through 2002. Under these contracts, any disruption of operating activity would allow Vermont Yankee to cancel or postpone deliveries until actually needed.
Vermont Yankee has contracted for uranium enrichment services through 2002. Vermont Yankee also has an enrichment contract with the DOE which expires in 2001. However, Vermont Yankee has exercised its right to partially terminate the DOE contract for the period 1990 to 1997.
Vermont Yankee has a contract with the United States Department of Energy ("DOE") for the permanent disposal of spent nuclear fuel. Under the terms of this contract, in exchange for the one-time fee discussed below and a quarterly fee of $.001 per KWH of electricity generated and sold, the DOE agrees to provide disposal services when a facility for spent nuclear fuel and other high-level radioactive waste is available, which is required by contract to be prior to January 31, 1998.
The DOE contract obligates Vermont Yankee to pay a one-time fee of $39.3 million for disposal costs for all spent fuel discharged through April 7, 1983. Although such amount has been collected in rates from the Sponsors, Vermont Yankee has elected to defer payment of the fee to the DOE as permitted by the DOE contract. The fee must be paid no later than the first delivery of spent nuclear fuel to the DOE. Interest accrues on the unpaid obligation based on the thirteen-week Treasury Bill rate and is compounded quarterly. Through 1994 Vermont Yankee accumulated approximately $54 million in an irrevocable trust to be used exclusively for defeasing this obligation at some future date provided the DOE complies with the terms of the aforementioned contract.
On December 31, 1991, the DOE issued a final rule modifying the Standard Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste. The amended final rule conforms with a March 17, 1989 ruling of the U.S. Court of Appeals for the District of Columbia that the $.001 per KWH fee in the Standard Contract should be based on net electricity generated and sold. The impact of the amendment on Vermont Yankee was to reduce the basis for the fee by 6% on an ongoing basis and to establish a receivable from the DOE for previous overbillings and accrued interest. Vermont Yankee has recognized in its rates the full impact of the amended final rule to the Standard Contract. The DOE is refunding the overpayments, including interest, to utilities over a four-year period ending in 1995 via credits against quarterly payments. Interest is based on the 90-day Treasury Bill Auction Bond Equivalent and will continue to accrue on amounts remaining to be credited. At December 31, 1994, 1993 and 1992 approximately $.0, $.9 and $1.6 million in principal and interest respectively, is reflected in other accounts receivable in the Vermont Yankee's Balance Sheet.
The average energy and capacity costs to the Company of energy generated at the Vermont Yankee plant was 4.60, 3.69, 4.71, 5.34 and 3.77 cents per KWH for the years 1990 through 1994, respectively.
The Company has been advised by the companies operating other nuclear generating stations in which the Company has an interest that they have contracted for certain segments of the nuclear fuel production cycle through various dates. Contracts for the remainder of the fuel cycle will be required but their availability, prices and terms cannot be predicted.
Nuclear Liability and Insurance.
The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $8.9 billion. Beyond that a licensee maintains an indemnity agreement with the Nuclear Regulatory Commission, but subject to Congressional approval. The first $200 million of liability coverage is the maximum provided by private insurance. The Secondary Financial Protection Program is a retrospective insurance plan providing additional coverage up to $8.7 billion per incident by assessing $79.3 million against each of the 110 reactor units that are currently subject to the Program in the United States, limited to a maximum assessment of $10 million per incident per nuclear unit in any one year. The maximum assessment is to be adjusted at least every five years to reflect inflationary changes. The Company's interests in the nuclear power units are such that it could become liable for an aggregate of approximately $4.4 million of such maximum assessment per incident per year.
Major long-term purchases.
Canadian Purchases - Under various contracts, the Company purchases from Hydro-Quebec capacity and associated energy. Under the terms of these contracts, the Company is required to pay certain fixed capacity costs whether or not energy purchases above a minimum level described in the contracts are made. Such minimum energy purchases must be made whether or not other less expensive energy sources might be available.
The Company will receive varying amounts of capacity and energy from two Hydro-Quebec contracts during the period 1995-2016. The contract between a group of Vermont utilities (Vermont Joint Owners) and Hydro-Quebec provides power over the entire period while a contract between the state of Vermont and Hydro-Quebec terminates on September 22, 1995. Additional contracts were negotiated between the Company and Hydro-Quebec which in effect reduce the amount of power the Company is required to purchase, as well as one signed in 1994 which reduces the cost to the Company.
The maximum net amount of capacity that the Company will purchase during the term of the agreements is 142.7 MW. The total commitment in the next five years to purchase power under these contracts is approximately $321 million, less approximately $112 million of power sellbacks, yielding a net cost of approximately $209 million.
Early in the Vermont Joint Owners contract, two sellback contracts were negotiated which reduced the net purchase of Hydro-Quebec power as well as delayed the purchase of about 24 MW of capacity and associated energy. In 1994, the Company negotiated a third sellback arrangement whereby the Company receives an effective discount on up to 70 MW of capacity in the 1996 contract year (declining to 30 MW in the 1999 contract year) in exchange for the right of Hydro-Quebec to reduce capacity deliveries by up to 50 MW beginning as early as 2004 until 2015, and the ability to reduce the amounts of energy delivered from a 75% to a 50% load factor up to five years beginning in 2000.
Details of these purchases and sell-back contracts are described in the table that follows (dollars in thousands):
Merrimack #2 - Merrimack #2 is a 320 MW capacity coal-fired steam unit located in Bow, New Hampshire, and is owned and operated by Public Service Company of New Hampshire ("PSNH"). In 1968 VELCO contracted with PSNH to purchase a block of 100 MW of the plant's output for 30 years and to pay a proportionate share of the plant's actual capacity and operating costs. Under an agreement dated February 10, 1968, between the Company and VELCO, the Company buys from VELCO at VELCO's cost 47.0 MW of that block for a 30-year period commencing May 1, 1968. Northeast Utilities (NU) has acquired all of PSNH's assets including the Merrimack #2 plant, pursuant to a merger agreement in 1991.
The Merrimack #2 unit is subject to air emission limits for sulfur dioxide ("SO2") and Nitrogen Oxides ("NOx") starting in 1995, mandated by the Clean Air Act Amendments of 1990 ("CAAA"). The CAAA establishes SO2 allowances to reduce SO2 emissions. PSNH expects to have sufficient SO2 allowances to meet CAAA SO2 requirements. If any gains are realized from the sale of excess allowances, the Company will receive its proportionate share from VELCO. Likewise, the Company will pay its share of any allowances purchased.
The CAAA NOx limits for Merrimack #2 are specified in Administrative Rules established by the state of New Hampshire. The NOx limits specified in the Rules that occur during the VELCO Contract term are effective May 31, 1995.
PSNH expects to comply with the Merrimack #2 NOx limits by installing Selective Catalytic Reduction ("SCR") equipment by May 31, 1995. The estimated SCR capital cost is $19 million and the estimated increase in operating costs from the SCR are $1.6 million annually. The SCR is expected to have a negligible effect on unit fuel efficiency. The Company will share on a pro-rata basis the SCR based on its share of the VELCO contract. The total cost to the Company of energy generated by the Merrimack #2 unit was 3.21 cents per KWH in 1994. The 1994 annual capacity factor was 68%.
Other Purchases.
Cogeneration/Small Power Qualifying Facilities - A number of small producers using hydroelectric, biomass, and refuse-burning generation are currently producing energy that the Company is purchasing. For the year ended December 31, 1994, the Company received 190,613 MWH from these sources for which it paid $18,893,051. The Company expects to purchase approximately 42 MW in each year 1995 through 1999. The total commitment in the next five years to purchase power from these qualifying facilities is approximately $105.9 million.
The Company continues to work with customers exploring the opportunities for either cogeneration by customers or the purchase by the Company of the output of small power qualifying facilities. Cogeneration is the production of electricity and usable thermal energy from the same fuel.
New York Power Authority - Prior to July 1, 1985, under agreements between the State and NYPA, the Department purchased St. Lawrence and Niagara Project power. The Company in turn contracted with the Department to purchase the St. Lawrence and Niagara Project power at cost, and credited the lower cost thereof to certain of the Company's retail customers. From July 1, 1985 through July 31, 1993, the St. Lawrence and/or Niagara Project power was purchased by the DPS and sold directly to residential customers in the Company's service territory.
The St. Lawrence Project power was reduced to one MW in July 1994 and will continue to be available to the Department at this level through 2002.
New England Power Pool - The Company, through VELCO, is a participant in the New England Power Pool ("NEPOOL"), which is open to all investor-owned, municipal and cooperative utilities in New England under an agreement in effect since 1971. The NEPOOL Agreement provides for joint planning and operation of generating and transmission facilities and also incorporates generating capacity reserve obligations and provisions regarding the use of major transmission lines and payment for such use. Because of its participation in NEPOOL, the Company's operating revenues and costs are affected to some extent by the operations of other participants in that agreement.
The primary purposes of NEPOOL are to provide energy reliability for the region, centralized economic dispatch and coordination of generation planning and construction by the individual participants. The Company's peak demand for 1994 occurred on January 17, 1994 and equaled 414.6 MW. At the time of this peak, the Company had a reserve margin of 31.9%. NEPOOL's peak for the year occurred on July 21, 1994 and totaled 20,519 MW. NEPOOL had a 21% reserve margin at the time of its 1994 peak.
Power Resources - Future.
The Company purchases about 90% of the power it needs, including the power it receives as part owner of the various Yankee nuclear plants. In 1994, about 30% of the Company's purchased power came from renewable sources, primarily water and wood. The Company's core business has no plans at this time to build any new generating facilities to supply power, instead it intends to satisfy customers' energy needs through a combination of power purchases and energy-efficiency services. Therefore, the Company uses a process called "integrated resource planning," or IRP, to help determine the resources necessary to meet future power needs. IRP is an evolving, on-going process. An interdisciplinary team representing various functional planning area works together continuously to coordinate and integrate planning. The primary objective of IRP is to provide reliable, least-cost energy resources consistent with the Company's policy to protect the environment. The choice of least-cost resources explicitly seeks a balance between traditional supply resources and energy efficiency investments with the Company's customers. Flexibility and diversity are investment guidelines designed to provide least- cost resources over a broad range of possible futures.
The resource plan calls for investments in energy efficiency through the 1990's with additional investments in energy-efficiency programs or power purchases beginning after the year 2000. The energy efficiency and power purchase commitments made in the late 1980's served the Company and its shareholders well during the recent recessionary downturn compared to the alternative practice of building power plants. The resources from developers of cogeneration projects were deferred due to decreased need. Certain power purchases from Hydro-Quebec were deferred until 1996. Energy efficiency investments associated with new customers and new end-uses naturally declined during the period of reduced load growth and new deferrable efficiency investments were postponed.
Based upon current load forecasts, the Company expects to be able to satisfy its load requirements into the first decade of the next century through its ownership in various generating facilities and purchases from various other New England, New York, Canadian utilities, Independent Power Producers, and Conservation and Load Management. Current load and capacity forecasts for NEPOOL indicate adequate reserves and availability of power for the region as a whole and the Northeast well past the year 2000.
TRANSMISSION
Vermont Electric Power Company, Inc.
Since 1958 VELCO has been engaged in the operation of a high-voltage transmission system which interconnects the electric utilities in the State including the areas served by the Company. VELCO is also engaged in the business of purchasing bulk power for resale, at cost, to the Company and the other electric utilities (cooperative, municipal and investor-owned) in Vermont (the "Vermont utilities") and transmitting such power for the Vermont utilities. Refer to Item 8 herein for a discussion of the 1985 Four Party Agreement between the Company, VELCO and two other major distribution companies in Vermont.
VELCO provides transmission services for the State of Vermont, acting by and through the Department, and for all of the electric distribution utilities in the State of Vermont. VELCO is reimbursed for its costs (as defined in the agreements relating thereto) for the transmission of power for such entities. The Company, as the largest electric distribution utility in Vermont, is the major user of VELCO's transmission system.
The Company owns 34,083 shares (56.8%) of the Class B common stock of VELCO, the balance being owned by other Vermont utilities. Each share of Class B common stock has one vote. The Company also owns 46,624 shares (46.6%) of the Class C preferred stock of VELCO, the balance being owned by other Vermont utilities. Shares of Class C preferred stock have no voting rights except the limited right to vote VELCO's shares of common stock in Vermont Electric Transmission Company, Inc. if certain dividend requirements are not met.
NEPOOL Arrangements.
VELCO participates for itself and as agent for the Company and twenty-one other Vermont utilities in NEPOOL (see "Business-New England Power Pool" for additional details).
Capitalization.
VELCO has authorized 92,000 shares of Class B common stock, $100 par value, of which 60,000 shares were outstanding on December 31, 1994 and 125,000 shares of Class C preferred stock, of which 100,000 shares were outstanding at December 31, 1994. On that date there were authorized and outstanding three issues of First Mortgage Bonds, aggregating $37,999,000, issued under an Indenture of Mortgage dated as of September 1, 1957, as amended, between VELCO and Bankers Trust Company, as Trustee (the "VELCO Indenture"). The issuance of bonds under the VELCO Indenture is unlimited in amount but is subject to certain restrictions.
New transmission and associated facilities will be required by VELCO in 1995 to transmit power to Vermont utilities. The costs of such facilities are presently estimated at $2,910,000 including allowance for funds used during construction calculated at a rate of approximately 4.7%. For a description of VELCO's properties, see "VELCO" under Item 2.



Item 2. Properties.
The Company. The Company's properties are operated as a single system which is interconnected by transmission lines of VELCO, New England Power Company and PSNH. The Company owns and operates 21 small generating stations with a total current nameplate capability of 66,370 KW, has a 1.78% joint- ownership interest in an oil generating plant in Maine, has a 20% joint- ownership interest in a wood, gas and oil-fired generating plant in Vermont, has a 1.73% joint-ownership interest in a nuclear generating plant in Connecticut, has a 46.08% joint-ownership interest in a transmission interconnection with Hydro-Quebec in Vermont and leases and operates two hydro generating stations from wholly owned subsidiaries, Bradford and East Barnet, 1,500 KW and 2,200 KW, respectively.
The electric transmission and distribution systems of the Company include about 614 miles of overhead transmission lines, about 7,199 miles of overhead distribution lines and about 213 miles of underground distribution lines which are located in Vermont except for about 23 miles of transmission lines which are located in New Hampshire and about two miles of transmission lines which are located in New York.
Connecticut Valley. Connecticut Valley's electric properties consist of two principal systems in New Hampshire which are not interconnected with each other but each of which is connected directly with facilities of the Company.
The electric systems of Connecticut Valley include about two miles of transmission lines and about 427 miles of overhead distribution lines and about nine miles of underground distribution lines.
All the principal plants and important units of the Company and its subsidiaries are held in fee. Transmission and distribution facilities which are not located in or over public highways are, with minor exceptions, located either on land owned in fee or pursuant to easements substantially all of which are perpetual. Transmission and distribution lines located in or over public highways are so located pursuant to authority conferred on public utilities by statute, subject to regulation of state or municipal authorities.
VELCO. VELCO's properties consist of about 483 miles of high voltage overhead transmission lines and associated substations. The lines connect on the west at the Vermont-New York state line with the lines of Niagara Mohawk Power Corporation near Whitehall, New York, and Bennington, Vermont and with the submarine cable of NYPA near Plattsburg, New York; on the south and east with lines of New England Power Company and PSNH; on the south with the facilities of Vermont Yankee; and on the north with lines of Hydro-Quebec through a converter station and tie line jointly owned by the Company and several other Vermont utilities.
VETCO. VETCO has approximately 52 miles of high voltage DC transmission line connecting at the Quebec-Vermont border in the Town of Norton, Vermont with the transmission line of Hydro-Quebec and connecting at the Vermont-New Hampshire border near New England Power Company's Moore hydro-electric generating station with the transmission line of New England Electric Transmission Corporation, a subsidiary of New England Electric System.
Item 3.

Item 3. Legal Proceedings.
On March 20, 1992, Sunnyside Cogeneration Associates filed suit in the United States District Court for the District of Vermont against the Company, CV Energy Resources, Inc. (CVER) and a subsidiary of CVER alleging damages in excess of five million dollars resulting from the parties inability to come to agreement on the terms of CVER's proposed investment in the plaintiff's waste coal cogeneration facility under construction in Sunnyside, Utah. The Company has filed an answer denying the allegations and does not expect the resolution of the case to have a material affect on the business or financial condition of the Company.
On December 30, 1994 the Company and its Board of Directors were named as defendants in a complaint filed in the United States District Court for the District of Vermont by three shareholders. The complaint alleges among other things, (i) that F. Ray Keyser, Jr., Chairman of the Company's Board of Directors, violated Section 8 of the Clayton Act, 15 U.S.C. Subchapter 19, which precludes certain interlocking directorships, (ii) that Mr. Keyser violated his fiduciary duties to the Company's stockholders by acquiring and operating a series of businesses in competition with the Company without offering those business opportunities to the Company, (iii) that the remaining individual defendants violated their fiduciary duties to the Company's stockholders by failing to analyze, or to cause management to analyze, diversification into propane and fossil fuels, and by failing to make the Company an effective competitor of alternative fuel companies, and (iv) that the Company violated the applicable provision of the Vermont General Corporation Law by failing to provide a list of the Company's stockholders. The complaint seeks an unspecified amount of damages (including treble damages against Mr.Keyser), attorney's fees and costs, a list of the Company's stockholders, and a court order to enjoin the defendants from alleged continuing violations of the law. Each of the individual defendants and the Company itself deny the allegations against them and intend to vigorously defend the complaint.
There are no other material pending legal proceedings, other than ordinary routine litigation incidental to the business, to which the Company or any of its subsidiaries is a party or to which any of their property is subject.
Item 4.

Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to security holders during the fourth quarter of 1994.
PART II
Item 5.

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.............. $ 22 $ 18 3/8 Second quarter............. 19 1/8 14 1/4 Third quarter.............. 15 1/2 12 1/8 Fourth quarter............. 14 1/2 12 3/8
First quarter.............. $ 25 5/8 $ 24 1/8 Second quarter............. 25 1/8 22 Third quarter.............. 24 3/4 23 1/4 Fourth quarter............. 23 3/4 20 1/8
(b) As of December 31, 1994, there were 16,961 holders of the Company's common stock, $6 par value.
(c) Common stock dividends have been declared quarterly. Cash dividends of $.355 per share were paid for all quarters of 1994 and 1993.
So long as any Senior Preferred Stock or Second Preferred Stock is outstanding, except as otherwise authorized by vote of two-thirds of each such class, if the Common Stock Equity (as defined) is, or by the declaration of any dividend will be, less than 20% of Total Capitalization (as defined), dividends on Common Stock (including all distributions thereon and acquisitions thereof), other than dividends payable in Common Stock, during the year ending on the date of such dividend declaration, shall be limited to 50% of the Net Income Available for Dividends on Common Stock (as defined) for that year; and if the Common Stock Equity is, or by the declaration of any dividend will be, from 20% to 25% of Total Capitalization, such dividends on Common Stock during the year ending on the date of such dividend declaration shall be limited to 75% of the Net Income Available for Dividends on Common Stock for that year. The defined terms identified above are used herein in the sense as defined in subdivision 8A of the Company's Articles of Association; such definitions are based upon the unconsolidated financial statements of the Company. As of December 31, 1994, the Common Stock Equity of the Company was 54.4% of total capitalization.
For additional information regarding dividend payment level and dividend restrictions see Item 8 herein.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Earnings Overview.
The Company's earnings per share of common stock declined by 34% in 1994 to $1.08 from $1.64 per share in 1993. The return on common equity was 7.2% for 1994 and 11.0% for 1993. Earnings per share of common stock and return on common equity for 1992 were $1.71 and 11.8%, respectively. In 1992, earnings and earnings per share of common stock were reduced by approximately $3.0 million and $.27, respectively, for an anticipated environmental cleanup. Weak sales, increased cost of operations and fourth quarter charges, discussed below and described in results of operations, are primarily responsible for reduced earnings for 1994.
During the fourth quarter of 1994, the Company incurred three non- recurring charges. The first resulted from cost disallowances associated with the Vermont Public Service Board (PSB) Rate Order described below, which reduced after tax earnings and earnings per share of common stock by approximately $1.8 million and $.16, respectively. The second resulted from the Company's decision to discontinue its proposed new headquarters office building which reduced after tax earnings and earnings per share of common stock by $1.7 million and $.14, respectively. The third resulted from writing down SmartEnergy Service Inc.'s investment in Green Technologies, Inc.'s common stock to reflect management's estimate of the decline in value of the investment. As a result, after-tax earnings and earnings per share of common stock were reduced by $.8 million and $.07, respectively.
Absent the non-recurring charges, net income and earnings per share of common stock would have been as follows (dollars in thousands):
Year Ended December 31 1994 1993 1992
Net income as reported $14,800 $21,292 $21,422 Non-recurring charges, net of taxes 4,336 - 2,965 ------- ------- ------- Net income before non-recurring charges $19,136 $21,292 $24,387 ======= ======= =======
Earnings per share of common stock before non-recurring charges $1.45 $1.64 $1.98
As a result of these non-recurring charges, the Company earned an 8.4% return on its Vermont utility business and a 1.1% return on non-utility investments. The combined non-utility investments return of 1.1% resulted from a 4.9% return from Catamount Energy Corporation and a 34.2% loss from SmartEnergy Services, Inc. primarily caused by the write down of its investment in Green Technologies, Inc. See Item 8 herein for additional details on the Company's non-utility investments.
A PSB Rate Order dated October 31, 1994, subsequently amended, allowed the Company a base retail rate increase of 5.07% or approximately $10.2 million effective with service rendered November 1, 1994. The Company had filed for an 8.9% or $17.9 million increase in its base retail rates in February 1994. The Rate Order also lowered the allowed rate of return on the Company's common stock equity from 12% to 10%. The allowed return on common stock equity is after deducting a .75% penalty based on the PSB's conclusions that there had been "mismanagement of power supply options" and because of "the Company's failed efforts to acquire all cost-effective energy efficiency resources." The Company disagrees with the PSB's conclusion.
Recognizing the need for financial flexibility in the face of the increasingly competitive marketplace, the Company's board of directors announced, on November 8, 1994, a new corporate strategy which includes a dividend targeted at approximately 60% of earnings; a program to purchase up to 2 million shares of its outstanding common stock in open market transactions; a new strategic plan to provide earnings growth and cost stability; and a further reduction in corporate spending to ensure that only projects and activities critical to reliable, cost-effective operations are funded.
These actions are part of a plan to both control costs and rates, and to help position the Company for growth and success into the next century in a more competitive, price sensitive environment. These moves will allow the Company to retain more capital in the business, provide increased financial flexibility and assure the Company's ability to take advantage of opportunities for growth.
Results of Operations.
Operating revenues and MWH sales A summary of MWH sales and operating revenues for 1994 and 1993 (and the related percentage changes from 1993) is set forth below:
Year-to-year fluctuations in total retail MWH sales are primarily affected by customer growth, Conservation and Load Management (C&LM) programs as well as relative prices of alternate energy sources, weather patterns and conservation induced by price changes and income elasticity responses of customers. Total retail MWH sales for 1994 were relatively flat compared to 1993, reflecting weak sales due to the state's slow economic growth and the effectiveness of C&LM programs. Although the Company was granted a 5.07% retail rate increase effective with service rendered November 1, 1994, retail revenues increased only 1.3%. Total Company retail MWH sales increased 1.4% and related revenues increased 2.0%. The increase is principally attributable to the September 1, 1993 change in power supplied to retail customers by the Company rather than as previously provided by the DPS. The impact was to increase retail sales and revenues by 25,714 MWH and $1.6 million in 1994.
The increase in retail revenues was offset by a decrease in other revenues reflecting elimination of the fee previously charged to the DPS for delivery of power and for providing billing and collection services.
Due to current market conditions, some of the Company's firm resale customers chose not to extend their contracts beyond October 1993. As a result, firm resale MWH sales and revenues declined for 1994 and 1993. However, one of those customers opted to purchase power from the Company based on market rates.
Entitlement MWH sales and revenues decreased 8.2% and 12.3%, respectively, due to reduced sell-back of the Hydro-Quebec Schedule C-1 and C- 2 power offset by increased sales made in conjunction with a swap arrangement with Commonwealth Electric as well as sales to UNITIL.
Other resale sales for 1994 increased 356,553 MWH and related revenues increased $7.8 million. These sales, made on a short-term basis, include sales to NEPOOL and other utilities in New England.
The Company continues to make every effort to maintain or increase resale sales despite the weak market for capacity and energy in the region.
Deferred revenues of $6.1 million in 1993 relate to the recognition of revenues deferred from 1991 to 1993.
The table below analyzes the components of increases or decreases in revenues (including DPS sales) compared to the prior year (dollars in thousands):
1994 1993 Revenue increase (decrease) from: Retail MWH sales $ 826 $(2,395) Retail rates 2,019 (84) Changes in firm resale sales (2,113) (888) Changes in entitlement sales (5,197) (983) Changes in other resale sales 8,006 14 Changes in other revenues (70) 306 Deferred revenues (6,075) 6,075 ------- ------- Net increase (decrease) over prior year $(2,604) $ 2,045 ======= =======
The minimal increase in retail MWH sales described above resulted in an $.8 million increase in retail revenues. The increase in retail rates of $2.0 million is due to the 5.07% retail rate increase that became effective with service rendered November 1, 1994. Retail MWH sales in 1993 were lower by 1.3%, compared to 1992 resulting in a $2.4 million decrease in retail revenues.
The decrease in entitlement sales for 1993 compared to 1992 is due to the scheduled refueling and unplanned shutdowns of Vermont Yankee reducing sales to UNITIL and Commonwealth Electric under a swap arrangement. In addition, in 1992, the Company was able to sell a portion of its Vermont Yankee entitlement to Public Service Company of New Hampshire.
Purchased power The Company purchases approximately 90% of its power needs under several contracts of varying duration. Over 30% of these purchases are from affiliated companies whereby the Company receives its entitlement share of the output. The Company's purchased power portfolio assures that a mix of sources and fuel types are available to meet the Company's long-term load growth while providing short and intermediate term opportunities to purchase or sell capacity and energy to reduce overall power costs. The percentages of the Company's energy sources from certain long-term commitments and Company- owned generating units were as follows:
Year Ended December 31 1994 1993 1992
Nuclear generating companies 39% 34% 34% Canadian imports 20 28 25 PSNH-coal 7 8 7 Company-owned hydro 5 5 5 Jointly owned units 5 4 4 Small power producers 5 5 3 Other sources 19 16 22 --- --- --- 100% 100% 100% === === ===
The Company has equity ownership interests in four nuclear generating companies: Vermont Yankee (VY), Maine Yankee (MY), Yankee Atomic (YA) and Connecticut Yankee (CY).
The VY nuclear plant, which provides approximately one-third of the Company's power supply, was unavailable from March 6 through April 21, 1992 and from August 27 through October 24, 1993 due to its scheduled refueling outages, and had unscheduled outages from April 7 to April 16, 1993 and December 6 to December 20, 1993.
The MY plant was shut down for refueling and maintenance from February 14 through April 19, 1992 and from July 30 through October 13, 1993.
See Note 2 to the Consolidated Financial Statements for details related to YA.
The CY plant was shut down for refueling and for an extended outage from October 17, 1991 through March 18, 1992 and for a scheduled refueling outage from May 15 through July 21, 1993.
There were no scheduled refueling outages and no major unscheduled outages during 1994.
During scheduled refueling outages, the Company purchases more costly replacement energy from NEPOOL and other sources to satisfy energy needs. In accordance with current rate-making treatment, the Company defers and amortizes to expense over their respective fuel cycles the incremental replacement energy and maintenance costs associated with these refueling outages for the Yankee plants and the Millstone #3 jointly owned nuclear generating unit. During 1993, the Company deferred $2.4 million and $6.5 million of replacement energy and capacity costs, respectively, for VY, MY, CY and Millstone #3.
In 1984, the Company and other Vermont utilities signed a long-term purchase power contract with the DPS for 150 MW of power provided by Hydro- Quebec. During 1987, the Company and eight other Vermont utilities signed a long-term purchased power contract with Hydro-Quebec for up to 450 MW of power until 2020. Approval of the 450 MW contract was received in 1990. See Note 13 to the Consolidated Financial Statements for further details related to the Hydro-Quebec power contracts.
Under a 30-year contract, which expires in 1998, the Company purchases 46.98 MW of capacity from Merrimack #2, a coal-fired generating plant owned by Northeast Utilities (NU). Vermont Electric Power Company, Inc., representing Vermont utilities, and NU negotiated an agreement which assures the continuation of this contract through 1998 under its original terms, thereby resolving past uncertainty relating to the contractual price of capacity and the availability of the unit to the Company.
The Company also owns 20 hydroelectric generating units which have a total nameplate capability of 41.2 MW and two gas-fired and one diesel-peaking units with a combined nameplate capability of 28.9 MW. In addition, the Company maintains joint-ownership interests in Joseph C. McNeil, a 53 MW wood, gas and oil-fired unit; Wyman #4, a 619 MW oil-fired unit; and Millstone #3, an 1149 MW nuclear unit. Millstone #3 was shut down from July 31 through November 7, 1993 for a refueling outage. The Company's percentage ownership in these units is 20%, 1.78% and 1.73%, respectively.
The Company, under long-term contracts, purchases power from a number of small power producers who own qualifying facilities under the Public Utility Regulatory Policies Act of 1978. These qualifying facilities produce energy using hydroelectric, wood, biomass, and refuse-burning generation. During 1994, the Company purchased 34.4 MW of which approximately 30.1 MW is associated with the Vermont Power Exchange and 3.9 MW with a New Hampshire/Vermont solid waste plant.
The Company engages in purchases and sales with other electric utilities and with NEPOOL to take advantage of immediate pricing and other market conditions. These purchases are included in Other sources in the table above.
The net cost components of purchased power for the past three years were as follows (dollars in thousands):
Purchased capacity costs decreased $3.2 million for 1994 resulting from a $15.7 million decrease in price offset by an increase of 14.5% or $12.5 million in the amount of MW purchased. These variances are primarily due to the absence of refueling outages for Vermont Yankee.
The increase in total purchased capacity costs for 1993 is due to an increase in MW purchased, primarily from small power producers.
In total, energy costs for 1994 are about the same as 1993. Cost per MWH purchased decreased 6.2% or $3.9 million offset by an increase of 6.2% or $3.7 million in the amount of MWH purchased.
Total energy costs increased $4.2 million for 1993 primarily due to a $6.5 million increase in price offset by a decrease of $2.3 million relating to a 4.1% decrease in the amount of MWH purchased. However, average cost per MWH purchased increased by 12.2%. The higher average cost is primarily due to increased MWH purchased from small power producers mandated by Federal and state legislation.
Energy costs are directly related to the variable prices of oil, nuclear fuel and coal but more importantly, to the proportion of the Company's purchased energy that comes from each of these fuel sources. The swap arrangement with Commonwealth Electric of Canal #2 power has increased the Company's reliance on oil as a source of electricity. Also, some Canadian purchased power contracts are tied to fossil fuel price indices. This will increase the Company's exposure to the variability of oil price volatility.
The Company is responsible for paying its entitlement percentage of decommissioning costs for VY, CY, MY and YA as well as its joint ownership percentage of decommissioning costs for Millstone #3. See Notes 2 and 13 to the Consolidated Financial Statements. Recently, the staff of the Securities and Exchange Commission has questioned certain current accounting practices of the electric utility industry, including the Company, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in financial statements of electric utilities. In response to these questions, the Financial Accounting Standards Board has agreed to review the accounting for nuclear decommissioning costs. If current electric utility industry accounting practices for such decommissioning costs are changed it is possible that annual provisions for decommissioning costs could increase, the total estimated costs for decommissioning could be recorded as a liability, and income from external decommissioning trusts could be reported as investment income instead of a reduction to decommissioning expense. The Company does not believe that such changes, if required, would have an adverse effect on results of operations due to its ability to recover decommissioning costs through the regulatory process. See Liquidity and Capital Resources - Competition, for related information.
The increase in production fuel costs of $.2 million for 1994 results from a 22.0% or 68,799 MWH increase in the amount of MWH generated mostly by one of the Company's jointly owned units, Millstone #3.
Production fuel costs decreased 21.1% or $.5 million in 1993, due to lower generation by the Company's jointly owned units.
In order to optimize its power mix for baseload, intermediate and peaking power, the Company engages in sales and purchases with other electric utilities, primarily in New England and with NEPOOL. These transactions typically take advantage of immediate pricing and other market conditions. The profits from these transactions are used to reduce revenue requirements for rate-making purposes.
As stated earlier, the Company is making every effort to maintain or increase these sales despite the weak resale market for excess capacity and energy in the region.
The Company's forecast indicates that net purchased power and production fuel costs will be approximately $103.5, $116.3, and $136.0 million for the period 1995 through 1997.
Production and transmission The Phase II transmission line began operation in November 1990. This service increased the maximum capacity of the Hydro- Quebec 450 KV DC line from 690 MW to 2000 MW and extended the Phase I line from Comerford, New Hampshire to Sandy Pond, Massachusetts. The Company uses this transmission path to deliver a portion of the Company's long-term Hydro- Quebec firm power contract. The Phase II project cost is approximately $487 million. The Company pays 5.132% of support costs or about $2.7 million annually. Also, the Company is obligated to pay a 4.421% share of the Phase I Hydro-Quebec capital costs or about $.5 million annually. Under the support agreement, the Company is eligible for savings associated with certain energy transactions by NEPOOL, which offset the Company's support cost obligations.
Variances for production and transmission expenses for 1994 and 1993 were minimal.
Other operation expenses Other operation expenses increased 13.2% or $4.8 million primarily due to the charge-off of approximately $2.9 million in costs related to the proposed new corporate headquarters office building, an increase in pension and benefit costs and regulatory commission expenses. Other operation expenses decreased $2.2 million for 1993 primarily due to an environmental reserve of $4.9 million established in December 1992 related to estimated costs associated with the cleanup of coal tar deposits discovered at the Company's Cleveland Avenue site, offset in part by the recognition of a postretirement benefit obligation in accordance with Statement of Financial Accounting Standards (SFAS) No. 106 effective January 1, 1993. For detailed information on SFAS No. 106, see Note 10 to the Consolidated Financial Statements and for a complete disclosure on environmental matters, see Note 13 to the Consolidated Financial Statements.
Depreciation The increases in depreciation expense for 1994 and 1993 are due to property additions and the installation of new computer systems in 1992 and 1993.
Income taxes Federal and state income taxes fluctuate with the level of pretax earnings. These taxes decreased for 1994 as a result of lower pre-tax earnings. However, the decrease was offset by the write-off of $1.6 million of SFAS No. 109 deferred tax assets which were expected to be collected from customers through rates. Recovery of these taxes was disallowed by the PSB in its October 31, 1994 Rate Order described in Earnings Overview.
During 1993, the Company recognized additional accumulated deferred income taxes of approximately $15 million and a net corresponding asset from customers of approximately $15 million reflecting future revenues that will be required when the temporary differences reverse and are settled in rates. Also, due to the Revenue Reconciliation Act which was passed on August 10, 1993, income tax expense increased by approximately $.3 million for the year 1993.
Other income and deductions Equity in earnings of affiliates decreased 14.3% for 1994, as compared to 1993. The decrease is attributable to a lower rate of return allowed by the Federal Energy Regulatory Commission to some of the Company's nuclear generating affiliates.
The increase in allowance for equity and borrowed funds used during construction for 1994 is due to an increase in capital expenditures and also due to higher rates used for capitalization of these funds. In 1993, AFDC was lower than in 1992 due to lower rates used for capitalization of these funds.
Other income (expenses), net, decreased approximately $.9 million for 1994 compared to 1993. During the fourth quarter of 1994, the Company wrote- down its investment in Green Technologies, Inc. by approximately $1.3 million to reflect management's estimate of the decline in value of the investment. This write-down is partially offset by higher income from non-utility subsidiaries as well as higher interest on temporary cash investments due to a combination of higher investment levels and interest rates during 1994.
Other income (expenses), net, decreased for 1993 due to lower prevailing interest rates and lower levels of investments resulting in decreased earnings from temporary cash investments offset by increased income from non-utility operations.
Interest on long-term debt The increase in interest on long-term debt for 1994 results from the issuance of $43 million of First Mortgage Bonds in December 1993. Interest on long-term debt decreased $3.0 million for 1993 primarily due to refinancing First Mortgage Bonds at lower interest rates.
Other interest expense Other interest expense increased approximately $.4 million for 1994 due to the 1993 FERC settlement related to certain wholesale customers. Other interest expense decreased $.9 million for 1993 mainly due to a FERC settlement related to certain wholesale customers. The decrease was offset in part by an increase in interest expense due to higher levels of short-term borrowings outstanding during 1993.
Cash Dividends Declared
Preferred
In January 1994, the Company redeemed 280,000 shares of preferred stock 9% dividend series at a premium of $.25 per share. This redemption resulted in a decrease in preferred dividends declared for 1994 compared to 1993.
Common
The increase in common dividends declared for 1994 results from an advanced quarterly common dividend declaration in December 1994 payable February 15, 1995. As a result, the accompanying Consolidated Financial Statements reflect five quarterly dividend declarations in 1994. The December 1994 declaration reflects the 44% reduction in future dividends paid per share.
The decrease in common dividends declared for 1993 as compared with 1992 is due to an advanced quarterly common dividend declaration in November 1992 payable February 12, 1993.
Liquidity and Capital Resources
Competition As described in Note 1 to the Consolidated Financial Statements, management believes that the Company meets the requirement of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation", but continues to evaluate significant changes in the regulatory and competitive environment to ensure and assess the Company's overall consistency with the criteria of SFAS No. 71. In the event the Company determines that it no longer meets the criteria for following SFAS No. 71, the accounting impact would be an extraordinary non-cash charge to operations of an amount that could be material. Although these conditions do not currently exist, the Company anticipates that in the future competition will place pressure on both unit sales and the price the Company can charge. As a result, increased competitive pressure in the electric utility industry may restrict the Company's ability to establish prices to recover embedded costs and may lead to a significant change in the manner in which rates are set by regulators from cost-based regulation to a different form of regulation that approximates market conditions. Singly or together these events may give rise to the discontinuance of SFAS No. 71 and, in addition, could diminish the Company's ability to recover its embedded costs of providing service.
Construction The Company's liquidity is primarily affected by the level of cash generated from operations, power contracts, and the funding requirements of its ongoing construction and C&LM programs. Cash flows from operating activities after dividends paid provided approximately $30.6 million in 1994, $18.7 million in 1993 and $30.7 million in 1992.
Consistent with the new Corporate Strategy announced by the Company's Board of Directors (Board) on November 8, 1994, construction expenditures over the next five years will be directed toward the funding of projects and activities critical to reliable, cost effective operations. In light of this, the Company is deferring some planned expenditures and also decided to discontinue its proposed new headquarters office building. Accordingly, during the fourth quarter of 1994, the Company wrote-off approximately $2.9 million of pre-tax costs related to the new headquarters office building. Excluding allowance for funds used during construction, construction expenditures plus expenditures for the Company's C&LM programs are estimated to average between $20-23 million for each of the next five years. The Company's goal is to finance approximately 100% of these annual expenditures with funds generated from operations.
Financing and Capitalization
Utility The level of short-term borrowings fluctuates based on seasonal corporate needs, the timing of long-term financings and market conditions. Short-term borrowings are supported by committed lines of credit and uncommitted loan facilities with several banks totaling $43.25 million. Short-term borrowings generally are reduced when long-term debt or equity securities are issued. In December 1993, the Company issued $43 million of long-term debt, of which $14.5 million replaced First Mortgage Bonds redeemed in October 1993 and $4.325 million replaced First Mortgage Bonds redeemed in January 1994. The balance was used to reduce short-term debt outstanding. In December 1994, the Company's wholly owned subsidiary, Connecticut Valley Electric Company Inc., issued a promissory note of $2.5 million under a five- year loan agreement. The proceeds were used to settle its 9 1/2% note of $2.5 million held by the parent company. In the past, the Company has been able to finance its construction and C&LM programs and it expects to meet future commitments.
In 1988, the Company sold a $12 million interest in certain customers' accounts receivable and unbilled revenues. Under the sales of accounts receivable agreement the Company can sell an additional $8 million of accounts receivable if certain accounts receivable ratio tests are satisfied. The original sale of customer accounts receivable and unbilled revenue was for a two-year period with an option that the Company may request, on each anniversary date, an extension for an additional year.
On November 8, 1994, the Board announced a new dividend policy that targeted future dividends at 60% of earnings. In light of the new policy, the current annual dividend of $1.42 was reduced 44% to $.80 effective with the first quarter dividend paid in February 1995. Accordingly, on December 5, 1994, the Board declared a quarterly common stock dividend of $.20 per share payable February 15, 1995 to shareholders of record on January 31, 1995. The dividend payment level will be reviewed regularly in light of capital needs, projected earnings' levels and other relevant factors. Also, the Board authorized the purchase of up to 2 million shares of its outstanding common stock in open market transactions. As of December 31, 1994, the Company had purchased 56,400 shares at an average price of $12.98 per share. These transactions are recorded as treasury stock, at cost, in the Company's Consolidated Balance Sheet.
As of February 8, 1995, the Company had purchased 74,700 shares at an average price of $12.99 per share.
In January 1994, the Company redeemed $7 million of the 9.00% Series Preferred Stock, $25 Par Value.
Beginning in August 1994, Dividend Reinvestment and Common Stock Purchase Plan, and Employee Stock Ownership Plan requirements were satisfied by the purchase of shares of common stock on the open market.
The Company's capital structure ratios (including amounts of long-term debt due within one year) for the past three years were as follows:
December 31 1994 1993 1992
Common stock equity 53% 52% 51% Preferred stock 9 10 11 Long-term debt 38 38 38 --- --- --- 100% 100% 100% === === ===
On July 21, 1994 and on August 5, 1994, Duff & Phelps, Inc. (Duff & Phelps) and Standard & Poor's Corporation (Standard & Poor's), respectively, lowered their rating on the Company's First Mortgage Bonds and Preferred Stock. Duff & Phelps stated that the downgrade reflects its concerns about the continuing recession in New England, intensifying competition in the utility industry and excess power in the northeastern region, as well as the Company's loss of wholesale revenues. Standard & Poor's revised its ratings outlook on the Company to "stable" from "negative" and stated "the downgrade reflects the Company's weak financial profile, adjusted for off-balance sheet obligations, primarily associated with purchased power, combined with the Company's low average business position." Standard & Poor's also stated "restrictive Vermont regulation, the state of the Vermont economy, nuclear asset concentration and increasing investments into non-regulated businesses are other factors impacting the Company's business position."
Current credit ratings for the Company's securities as reaffirmed, in mid-1994, by Duff & Phelps and Standard & Poor's are as follows:
Duff & Standard Phelps & Poor's
First Mortgage Bonds BBB+ BBB Preferred Stock BBB- BBB-
The decline in the Company's credit ratings will likely make the terms and conditions of borrowing more stringent, and increase the cost of capital. Currently, the Company does not anticipate issuing preferred stock or long- term debt in the near future.
Non-Utility Catamount Energy Corporation, a wholly owned subsidiary of the Company, maintains an Irrevocable Standby Letter of Credit with a bank to borrow up to an aggregate amount of $2.3 million to replace its share of cash in the Appomattox Cogeneration Limited Partnership's Project Debt Service Reserve Fund. This Letter of Credit is for a one-year term with annual extensions available and requires fees totaling 2.527% of credit available.
SmartEnergy Services, Inc., also a wholly owned subsidiary of the Company, maintains a $1.0 million revolving line of credit with a bank to provide working capital and financing assistance for investment purposes.
Financial obligations of the non-utility wholly owned subsidiaries are non-recourse to the Company.
Conservation and Load Management Programs (C&LM) The primary purpose of these programs is to offset the need for long-term power supply and delivery resources that are more expensive to purchase or develop than customer- efficiency programs. Expenditures in 1993 and 1994 were $9.9 million and $6.2 million, respectively, and are expected to be approximately $6.0 million in 1995. C&LM expenditure levels are adjusted on an ongoing basis based on the cost-effectiveness of programs compared to other options.
The October 31, 1994 PSB Rate Order allowed the recovery of $13.9 million of C&LM expenditures and lost revenues, deferred since the prior PSB rate order which became effective September 1, 1991, over a five-year period beginning November 1, 1994 through October 31, 1999. The Company had requested the recovery of $14.6 million of such deferred C&LM expenditures and lost revenues. Accordingly, during 1994, the Company wrote-off approximately $.7 million of costs disallowed by the PSB in its October 31, 1994 Rate Order. For additional information regarding the PSB Rate Order, see Earnings Overview.
In addition, the Company is involved in several cases in Vermont related to C&LM activities including the role of fuel switching as a C&LM resource and the level of externalities to be recognized in Integrated Resource Planning and C&LM cost-effectiveness testing. On October 31, 1994, the Company also filed its Integrated Resource Plan, which describes the Company's long-term resource acquisition plans including C&LM. Currently, the Company is involved in cooperative efforts with the DPS to settle many issues related to C&LM.
Diversification Catamount Energy Corporation (Catamount) was formed for the purpose of investing in non-regulated energy-related projects. Currently, Catamount, through its wholly owned subsidiaries, has interests in four operating independent power projects located in Rumford, Maine; East Ryegate, Vermont; Hopewell, Virginia; and Williams Lake, British Columbia, Canada.
SmartEnergy Services, Inc. was formed for the purpose of effectively providing reliable, energy-efficient products and services, including the rental of electric water heaters.
Rates The Company recognizes that adequate and timely rate relief is necessary if the Company is to maintain its financial strength, particularly since Vermont regulatory rules do not allow for changes in purchased power and fuel costs to be passed on to consumers through rate adjustment clauses. The Company's practice of reviewing costs periodically will continue and rate increases will be requested when warranted. For information regarding a PSB Rate Order issued on October 31, 1994 and subsequently amended, see Earnings Overview. The Company anticipates filing for future rate increases when cost containment efforts are insufficient to offset the increasing cost of providing service, primarily purchased power.
Inflation The annual rate of inflation as measured by the Consumer Price Index was 2.7% for 1994 and 1993, and 2.9% for 1992. The Company's revenues, however, are based on rate regulation that generally recognizes only historical costs. Although the rate of inflation has eased in recent years, it continues to have an impact on most aspects of the business.
Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements and Supplementary Data Page No. Report of Independent Public Accountants............................. 30
Financial Statements:
Consolidated Statement of Income for each of the three years ended December 31, 1994............................... 31
Consolidated Statement of Cash Flows for each of the three years ended December 31, 1994........................... 32
Consolidated Balance Sheet at December 31, 1994 and 1993.......................................................... 33
Consolidated Statement of Capitalization at December 31, 1994 and 1993........................................ 35
Consolidated Statement of Changes in Common Stock Equity for each of the three years ended December 31, 1994................................................. 36
Notes to Consolidated Financial Statements......................... 37
Report of Independent Public Accountants To the Board of Directors of Central Vermont Public Service Corporation:
We have audited the accompanying consolidated balance sheet and statement of capitalization of Central Vermont Public Service Corporation and its wholly owned subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of income, changes in common stock equity and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Central Vermont Public Service Corporation and its wholly owned subsidiaries as of December 31, 1994 and 1993 and the results of their operations and cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Boston, Massachusetts February 6, 1995
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 Summary of significant accounting policies
Consolidation The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries.
Regulation The Company is subject to regulation by the Vermont Public Service Board (PSB), the Federal Energy Regulatory Commission (FERC) and, to a lesser extent, the public utilities commissions in other New England states where the Company does business, with respect to rates charged for service, accounting and other matters pertaining to regulated operations. As such, the Company currently prepares its financial statements in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation, and records various regulatory assets and liabilities. In order for a company to report under SFAS No. 71, the Company's rates must be designed to recover its costs of providing service, and the Company must be able to collect those rates from customers. If rate recovery of these costs becomes unlikely or uncertain, whether due to competition or regulatory action, these accounting standards may no longer apply to the Company's regulated operations. Management believes that the Company currently meets the criteria for continued application of SFAS No. 71, but will continue to evaluate significant changes in the regulatory and competitive environment to assess the Company's overall consistency with the criteria of SFAS No. 71. In the event the Company determines that it no longer meets the criteria for applying SFAS No. 71, the accounting impact would be an extraordinary non-cash charge to operations of an amount that could be material.
Revenues Estimated unbilled revenues are recorded at the end of accounting periods. Unbilled revenues of approximately $18.6 million, $18.3 million and $18.5 million for 1992, 1993 and 1994, respectively, are included in revenues on the Consolidated Statement of Income.
Maintenance Maintenance and repairs, including replacements not qualifying as retirement units of property, are charged to maintenance expense. Replacements of retirement units are charged to utility plant. The original cost of units retired plus the cost of removal, less salvage, is charged to the accumulated provision for depreciation.
Depreciation The Company uses the straight-line remaining life method of depreciation. Total depreciation expense was approximately 3.5% of the cost of depreciable utility plant for each of the years 1992 through 1994.
Income Taxes The Company records income taxes in accordance with SFAS No. 109, Accounting for Income Taxes, which requires an asset and liability approach to determine income tax liabilities. The standard recognizes tax assets and liabilities for the cumulative effect of all temporary differences between financial statement carrying amounts and the tax basis of assets and liabilities, see Note 11. The deferred method under Accounting Principle Board's Opinion 11, was applied in 1992. Deferred income taxes were provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. Investment tax credits associated with utility plant are deferred and amortized ratably to income over the lives of the related properties. Investment tax credits associated with non-utility plant are recognized as income in the year realized.
Allowance for Funds During Construction Allowance for funds used during construction (AFDC) is the cost, during the period of construction, of debt and equity funds used to finance construction projects. The Company capitalizes AFDC as a part of the cost of major utility plant projects to the extent that costs applicable to such construction work in progress have not been included in rate base in connection with rate-making proceedings. AFDC equity represents a current non-cash credit to earnings which is recovered over the life of the property. The AFDC rates used by the Company were 10.51%, 5.09% and 8.05% for the years 1992 through 1994, respectively.
Regulatory Assets and Other Deferred Charges Certain costs are deferred and amortized in accordance with authorized or expected rate-making treatment. The major components of these costs are $19.2 million for Conservation and Load Management, $12.4 million for Yankee Atomic Electric Company dismantling costs, $10.6 million for SFAS No. 109, and $4.8 million of restructuring costs. During regular nuclear refueling outages, the increased costs attributable to replacement energy purchased from NEPOOL and maintenance costs are deferred and amortized ratably to expense until the next regularly scheduled refueling shutdown. The Company earns a return on the unamortized replacement energy and maintenance costs. See Note 2 to the Consolidated Financial Statements for discussion of the costs associated with the discontinued operation of the Yankee Atomic Nuclear Power Corporation nuclear power plant.
Purchased Power The Company records the annual cost of power obtained under long-term contracts as operating expenses. Since these contracts, as more fully described in Note 13, do not convey to the Company the right to use property, plant, or equipment, they are considered executory in nature. This accounting treatment is in contrast to the Company's commitment with respect to the Hydro Quebec Phase I and II transmission facilities which are considered capital leases. As such, the Company has recorded a liability for its commitment under the Phase I and II arrangements and recognized an asset for the right to use these facilities.
Note 2 Investments in affiliates
The Company uses the equity method to account for its investments in the following companies (dollars in thousands): December 31 Ownership 1994 1993 Nuclear generating companies: Vermont Yankee Nuclear Power Corporation 31.3% $16,916 $16,811 Connecticut Yankee Atomic Power Company 2.0% 2,011 2,016 Maine Yankee Atomic Power Company 2.0% 1,338 1,349 Yankee Atomic Electric Company 3.5% 813 836 ------- ------- 21,078 21,012 Vermont Electric Power Company, Inc.: Common stock 56.8% 3,494 3,498 Preferred stock 2,193 2,453 ------- ------- $26,765 $26,963 ======= =======
Each sponsor of the nuclear generating companies is obligated to pay an amount equal to its entitlement percentage of fuel, operating expenses (including decommissioning expenses) and cost of capital and is entitled to a similar share of the power output of the plants. The Company's entitlement percentages are identical to the ownership percentages except that Vermont Yankee's entitlement percentage is 35%. The Company is obligated to contribute its entitlement percentage of the capital requirements of Vermont Yankee and Maine Yankee and has a similar, but limited, obligation to Connecticut Yankee. The Company is responsible for paying its entitlement percentage of decommissioning costs for Vermont Yankee, Connecticut Yankee, Maine Yankee and Yankee Atomic as follows (dollars in millions):
CVPS's Total Share of Date of Estimated CVPS's Funded Study Obligation Obligation Obligation Nuclear generating companies: Vermont Yankee 1993 $312.7 $109.4 $40.3 Maine Yankee 1993 $316.6 $6.3 $2.2 Connecticut Yankee 1992 $294.2 $5.9 $3.0 Yankee Atomic 1994 $370 $13.0 $3.6
On February 26, 1992, the Board of Directors of Yankee Atomic decided to permanently discontinue operation of their plant, and to decommission the facility.
The Company relied on Yankee Atomic for less than 1.5% of its system capacity. Presently, purchased power costs billed to the Company by Yankee Atomic, which include a provision for ultimate decommissioning of the unit, are being collected from the Company's customers via existing retail rate tariffs.
On March 18, 1993, the FERC approved a settlement agreement regarding the decommissioning plan, recovery of plant investment and all issues with respect to prudency of the decision to discontinue operation which included $247 million of decommissioning costs in 1992 dollars. Based on a new study developed by Yankee Atomic, decommissioning costs are approximately $370 million in 1994 dollars. The increase results primarily from delays in finding a permanent repository for its spent nuclear fuel. The new study is subject to FERC approval. Yankee Atomic is currently collecting from sponsors decommissioning costs based on $247 million in 1992 dollars and anticipates to begin collecting from sponsors based on $370 million in November 1995. The Company's share of the increase in decommissioning costs is approximately $4.3 million.
The Company's total current share of its cost with respect to Yankee Atomic's decision to discontinue operation is approximately $12.4 million. This amount is reflected in the accompanying balance sheet both as a regulatory asset and deferred power contract obligation (current and non- current).
The Company believes that its proportionate share of Yankee Atomic costs will be recovered through the regulatory process and, therefore, the ultimate resolution of the premature retirement of the plant will not have a material adverse effect on the Company's earnings or financial condition.
Although the estimated costs of decommissioning are subject to change due to changing technologies and regulations, the Company expects that the nuclear generating companies' liability for decommissioning, including any future changes in the liability, will be recovered in their rates over their operating or license lives.
The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $8.9 billion. Beyond that a licensee maintains an indemnity agreement with the Nuclear Regulatory Commission, but subject to Congressional approval. The first $200 million of liability coverage is the maximum provided by private insurance. The Secondary Financial Protection Program is a retrospective insurance plan providing additional coverage up to $8.7 billion per incident by assessing $79.3 million against each of the 110 reactor units that are currently subject to the Program in the United States, limited to a maximum assessment of $10 million per incident per nuclear unit in any one year. The maximum assessment is to be adjusted at least every five years to reflect inflationary changes. The Company's interests in the nuclear power units are such that it could become liable for an aggregate of approximately $4.4 million of such maximum assessment per incident per year.
Summarized financial information for Vermont Yankee Nuclear Power Corporation is as follows (dollars in thousands):
Earnings 1994 1993 1992
Operating revenues $162,757 $180,145 $175,919 Operating income $14,355 $16,441 $16,304 Net income $6,588 $7,794 $7,921
Company's equity in net income $2,067 $2,434 $2,476
December 31 Investment 1994 1993
Current assets $ 41,416 $ 40,136 Non-current assets 470,726 429,634 -------- -------- Total assets 512,142 469,770
Less: Current liabilities 37,287 32,021 Non-current liabilities 420,382 383,585 -------- -------- Net assets $ 54,473 $ 54,164 -------- -------- Company's equity in net assets $ 16,916 $ 16,811
Included in Vermont Yankee's revenues shown above are sales to the Company of $52.9 million, $52.3 million and $53.6 million for 1992 through 1994, respectively. These amounts are reflected as purchased power net of deferrals and amortization in the accompanying Consolidated Statement of Income.
Vermont Electric Power Company, Inc. (Velco) and its wholly owned subsidiary Vermont Electric Transmission Company, Inc. (Vetco) own and operate transmission systems in Vermont over which bulk power is delivered to all electric utilities in the state. Velco has entered into transmission agreements with the state of Vermont and the electric utilities and under these agreements bills all costs, including interest on debt and a fixed return on equity, to the state and others using the system. These contracts enable Velco to finance its facilities primarily through the sale of first mortgage bonds. Included in Velco's revenues shown below are transmission services to the Company (reflected as production and transmission in the accompanying Consolidated Statement of Income) amounting to $8.3 million, $8.9 million and $8.4 million for 1992 through 1994, respectively.
Velco operates pursuant to the terms of the 1985 Four-Party Agreement (as amended) with the Company and two other major distribution companies in Vermont. Although the Company owns 56.8% of Velco's outstanding common stock, the Four-Party Agreement effectively restricts the Company's control of Velco. Therefore, Velco's financial statements have not been consolidated. The Four- Party Agreement continues in full force and effect until May 1995 and will be extended for an additional two-year term in May 1995, and every two years thereafter, unless at least ninety (90) days prior to any two-year anniversary any party shall notify the other parties in writing that it desires to terminate the agreement as of such anniversary. No such notification has been filed by the parties. The Company also owns 46.6% of Velco's outstanding preferred stock, $100 par value.
Summarized financial information for Velco is as follows (dollars in thousands):
Earnings 1994 1993 1992
Transmission revenues $16,761 $17,891 $16,722 Operating income $3,350 $4,423 $4,379 Net income $1,296 $1,375 $1,494
Company's equity in net income $638 $698 $749
December 31 Investment 1994 1993
Current assets $16,549 $15,181 Non-current assets 53,175 55,018 ------- ------- Total assets 69,724 70,199
Less: Current liabilities 15,941 13,180 Non-current liabilities 42,909 45,626 ------- ------- Net assets $10,874 $11,393 ======= ======= Company's equity in net assets $ 5,687 $ 5,951
Note 3 Non-utility investments
The Company's wholly owned subsidiary, Catamount Energy Corporation (Catamount) invests through its wholly owned subsidiaries in non-regulated, energy-related projects. Certain financial information for Catamount's investments is set forth in the table that follows (dollars in thousands):
The Rumford project was placed in service on August 1, 1990. The Ryegate and Williams Lake projects began commercial operation on November 1, 1992 and April 2, 1993, respectively. On October 26, 1992, Appomattox purchased a 50% partnership interest in Appomattox Cogeneration which owns a power sales agreement associated with a cogeneration facility currently in operation.
In January 1994, Catamount purchased an additional 4.185% limited partnership interest in Rumford Cogeneration Co. This additional investment increased Rumford's ownership in the project to 15.1%.
SmartEnergy Services, Inc. (SmartEnergy) also is a wholly owned subsidiary of the Company, whose purpose is to cost effectively provide reliable, energy efficient products and services, including the rental of electric water heaters. Prior to January 1, 1993, the rental electric water heater program was part of the Company's core electric business and reported as non-operating income.
On October 1, 1993, SmartEnergy purchased for $1.2 million, 304,125 shares (5%) of Green Technologies, Inc. (Green Technologies) common stock and on September 19, 1994, purchased for $540,000, an additional 120,000 shares (1.8%). This investment increased SmartEnergy's ownership in Green Technologies to 6.8%. Green Technologies of Boulder, Colorado, currently manufactures Green Plug electricity savers for several types of household appliances. SmartEnergy uses the cost method of accounting for its investment in Green Technologies. During the fourth quarter of 1994, SmartEnergy wrote- down its investment in Green Technologies by approximately $1.3 million to reflect management's estimate of the permanent decline in value of the investment. SmartEnergy's investment in Green Technologies was approximately $.42 million and $1.2 million at December 31, 1994 and 1993, respectively.
Note 4 Redeemable preferred stock
Commencing in 1998, the 8.30% Dividend Series Preferred Stock is redeemable at par through a mandatory sinking fund in the amount of $1.0 million per annum, and at its option, the Company may redeem at par an additional non-cumulative $1.0 million per annum.
Note 5 Common Stock
On November 8, 1994, the Company's board of directors (Board) announced a new dividend policy that targeted future dividends at 60% of earnings. In light of the new policy, the current annual dividend of $1.42 was reduced 44% to $.80 effective with the first quarter dividend paid in February 1995. Accordingly, on December 5, 1994, the Board declared a quarterly common stock dividend of $.20 per share payable February 15, 1995 to shareholders of record on January 31, 1995. The dividend payment level will be reviewed regularly in light of capital needs, projected earnings levels and other relevant factors. Also, the Board authorized the purchase of up to 2 million shares of its outstanding common stock in open market transactions. As of December 31, 1994, the Company had purchased 56,400 shares at an average price of $12.98 per share. These transactions are recorded as treasury stock, at cost, in the Company's Consolidated Balance Sheet.
As of February 8, 1995, the Company had purchased 74,700 shares at an average price of $12.99 per share.
Note 6 Long-term debt and sinking fund requirements
Based on issues outstanding at December 31, 1994, the aggregate amount of long-term debt maturities and sinking fund requirements (exclusive of the amount that may be satisfied by property additions) are approximately $4.2 million, $1.0 million, $3.0 million, $20.5 million and $5.5 million for the years 1995 through 1999, respectively. Substantially all property and plant is subject to liens under the First Mortgage Bonds.
Note 7 Financial instruments
The estimated fair values of the Company's financial instruments at December 31, 1994 are as follows (dollars in thousands):
Carrying Fair Amount Value
Cash and temporary cash investments $ 7,559 $ 7,559 Short-term debt $ 11,511 $ 11,511 Investments $ 424 $ 424 Sale of accounts receivable and unbilled revenues $ 12,000 $ 12,000 Redeemable preferred stock $ 20,000 $ 18,790 Long-term debt $124,387 $119,374
The carrying amount for cash, temporary cash investments and short-term debt approximates fair value because of the short maturity of those instruments.
The carrying amount and the fair value of the Company's investment in Green Technologies, Inc. reflects management's estimate of the realizable value of the investment.
The carrying amount for the sale of accounts receivable and unbilled revenues approximates fair value because of the short maturity of those instruments.
The fair value of the Company's redeemable preferred stock and long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same remaining maturation.
Anticipated regulatory treatment of any excess or decline in the fair value relative to the carrying value of the Company's financial instruments, if they were settled at amounts approximating those above, would result in an increase or decrease in the Company's rates over a prescribed amortization period. Accordingly, any settlement would not result in a material impact on the Company's financial position or results of operations.
The Company has no financial instruments that fall under the guidance of SFAS No. 119, Disclosure about Derivative Financial Instruments and Fair Value of Financial Instruments.
In May 1993, the FASB issued SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, effective for fiscal years beginning after December 15, 1993. SFAS No. 115 addresses the accounting and reporting for investments in equity securities that have readily determinable fair values and for all investments in debt securities. The Company has the following investments that are covered by the principles of SFAS No. 115: temporary cash investments classified as trading activities and reported at market value, and its available for sale investment in Green Technologies, Inc. For additional information, see Note 3 herein. The adoption of SFAS No. 115 had no material impact on the Company's financial position or results of operations.
Note 8 Accounts receivable
In 1988 the Company entered into an agreement to sell up to $20 million of certain accounts receivable and unbilled revenues. At December 31, 1994 and 1993, a total of $12 million of accounts receivable and unbilled revenues were sold under an accounts receivable facility.
Accounts receivable and unbilled revenues that have been sold were transferred with limited recourse. A pool of assets, varying between 3% to 5% of the accounts receivable and unbilled revenues sold, are set aside for this potential recourse liability. Accounts receivable and unbilled revenues are reflected net of sales of $4.2 million and $7.8 million, respectively, at December 31, 1994 and $4.7 million and $7.3 million, respectively, at December 31, 1993.
Accounts receivable are also reflected net of an allowance for uncollectible accounts of $1.0 million and $.9 million at December 31, 1994 and 1993, respectively.
Note 9 Short-term debt
Utility
The Company uses committed lines of credit and uncommitted loan facilities to finance its construction and C&LM programs, on a short-term basis, and for other corporate purposes. As of December 31, 1994, the Company had $18.25 million of committed lines of credit and $25 million of uncommitted loan facilities which are normally renewed upon expiration and require annual fees ranging from zero to .25% of an individual line. Borrowings under these short-term debt arrangements are at interest rates ranging from less than prime to the prime rate. The Company had $11.5 million and $1.4 million of outstanding short-term debt at December 31, 1994 and 1993, respectively, at average interest rates of 5.22% for 1994 and 3.61% for 1993.
Non-Utility
Catamount maintains an Irrevocable Standby Letter of Credit with a bank to borrow up to an aggregate amount of $2.3 million to replace its share of cash in the Appomattox Cogeneration Limited Partnership's Project Debt Service Reserve Fund. This Letter of Credit is for a one-year term with annual extensions available and requires fees totaling 2.527% of credit available. At December 31, 1994 and 1993, there were no borrowings outstanding under this Letter of Credit. Catamount believes it will not have to perform under this agreement because the likelihood of default by the primary party is remote.
SmartEnergy maintains a $1.0 million revolving line of credit with a bank to provide working capital and financing assistance for investment purposes. SmartEnergy had $846,000 and $696,000 of outstanding short-term debt at December 31, 1994 and 1993, respectively, at average interest rates of 7.29% for 1994 and 6.08% for 1993.
Financial obligations of the non-utility wholly owned subsidiaries are non-recourse to the Company.
Note 10 Pension and postretirement benefits
The Company has a non-contributory trusteed pension plan covering all employees (union and non-union). Under the terms of the pension plan, employees are generally eligible for monthly benefit payments upon reaching the age of 65 with a minimum of five years of service. The Company's funding policy is to contribute, at least, the statutory minimum to a trust. The Company is not required by its union contract to contribute to multi-employer plans.
The projected unit credit actuarial cost method was used to compute net pension costs and the accumulated and projected benefit obligations. The change in the accumulated benefit obligation and projected benefit obligation for 1993 and 1994 results primarily from changes in plan assumptions. The following table sets forth the funded status of the pension plan and amounts recognized in the Company's Balance Sheet and Statement of Income (dollars in thousands): December 31 1994 1993 1992 Funded status of the plan Vested benefit obligation $35,869 $35,837 $27,899 Non-vested benefit obligation 312 493 439 ------- ------- ------- Accumulated benefit obligation $36,181 $36,330 $28,338 ------- ------- -------
Projected benefit obligation $46,669 $49,743 $39,001 Market value of plan assets (primarily equity and fixed income securities) 44,115 46,074 39,768 ------- ------- ------- Projected benefit obligation more (less) than market value of plan assets 2,554 3,669 (767) Unrecognized net transition assets 1,608 1,768 1,929 Unrecognized prior service costs (3,178) (3,568) (3,084) Unrecognized net gain 5,963 1,498 5,314 ------- ------- ------- Net pension liability 6,947 3,367 3,392 Less regulatory asset for restructuring costs 1,974 - - ------- ------- ------- Effective accrued pension costs $ 4,973 $ 3,367 $ 3,392 ------- ------- -------
Net pension costs include the following components Service cost $ 2,065 $ 1,491 $ 1,307 Interest cost 3,694 3,377 3,065 Actual return on plan assets 515 (6,800) (4,137) Net amortization and deferral (4,095) 3,391 890 ------- ------- ------- Pension costs 2,179 1,459 1,125 Amortization of regulatory asset 261 - - ------- ------- ------- Effective pension costs 2,440 1,459 1,125 Less amount allocated to other accounts 318 276 223 ------- ------- ------- Net pension costs expensed $ 2,122 $ 1,183 $ 902 ------- ------- -------
Assumptions used in calculating pension cost were as follows:
December 31 1994 1993 1992
Weighted average discount rates 8.50% 7.25% 8.50% Expected long-term return on assets 9.50% 9.75% 10.25% Rate of increase in future compensation levels 5.00% 4.75% 5.50%
The Company sponsors a defined benefit postretirement medical plan that covers all employees who retire with ten years or more of service after age 45.
Effective January 1, 1993, the Company adopted, on a prospective basis, SFAS No. 106, Employer's Accounting for Postretirement Benefits Other Than Pensions (OPEB) which requires accrual of the expected costs of such benefits during the employees' years of service. In 1994, the Company adopted a policy to fund its OPEB obligation through a Voluntary Employees' Benefit Association and 401(h) Subaccount in its Pension Plan.
The following table sets forth the plan's funded status and amounts recognized in the Company's Balance Sheet and the amount of expense charged to the Company's Statement of Income in accordance with SFAS No. 106 (dollars in thousands): December 31 1994 1993 Accumulated postretirement benefit obligation Retirees $(8,265) $(5,098) Fully eligible active plan participants (521) (1,207) Other active plan participants (806) (1,293) Plan assets at fair value 744 - ------- ------- Accumulated postretirement benefit obligation in excess of plan assets (8,848) (7,598) Unrecognized transition obligation 5,485 6,253 Unrecognized net loss 337 351 ------- ------- Accrued postretirement benefit cost (3,026) (994) Regulatory asset for restructuring costs 2,008 - ------- ------- Effective accrued postretirement benefit costs $(1,018) $ (994) ======= ======= Net postretirement benefit cost includes the following components Service cost $ 194 $ 168 Interest cost 682 588 Actual return on plan assets 1 - Deferral of asset gain during the year (1) - Amortization of transition obligation over a twenty-year period 305 329 ------- ------- Postretirement benefit cost 1,181 1,085 Amortization of regulatory asset 265 - ------- ------- Effective postretirement benefit cost 1,446 1,085 Less amount allocated to other accounts 172 205 ------- ------- Net postretirement benefit cost expensed $ 1,274 $ 880 ======= =======
Assumptions used in the per capita costs of the accumulated postretire- ment benefit obligation were as follows:
December 31 1994 1993 Per capita percent increase in health care costs: Pre-65 9.50% 9.50% Post-65 8.00% 6.00% Weighted average discount rates 8.50% 7.25% Rate of increase in future compensation levels 5.00% 4.75%
Health care trend rates are assumed to decrease to 6.0% for pre-65 and 5.5% for post-65 for the year 2001 and thereafter.
This decrease results from changes to the retiree medical plan limiting the cost for employees retiring after 1995 to the 1995 per participant cost. Increasing the assumed health care cost trend rates by one percentage point in each year would have resulted in an increase of approximately $709,000 in the accumulated postretirement benefit obligation as of January 1, 1995, and an increase of about $57,000 in the aggregate of the service cost and interest cost components of net periodic postretirement benefit cost for 1994. Prior to 1993, the Company expensed OPEB's costs as benefits were paid. Such costs totaled $546,000 for 1992.
Effective January 1, 1994, the Company adopted, on a prospective basis, SFAS No. 112, Employers' Accounting for Postemployment Benefits which requires accrual of the expected cost of postemployment benefits provided to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement. The Company provides postemployment benefits consisting of long-term disability benefits, and prior to January 1, 1994 expensed these costs as benefits were paid. Such costs total $91,000 and $156,000 for 1992 and 1993, respectively. The accumulated postemployment benefit obligation at January 1, 1995 of approximately $1.3 million is reflected in the accompanying balance sheet as a deferred postemployment benefit obligation (current and non-current) and is offset by a corresponding regulatory asset of approximately $1.0 million. The PSB in its October 31, 1994 Rate Order allowed the Company to recover the regulatory asset over a 7-1/2 year period beginning November 1, 1994 through April 30, 2002. The postemployment benefit cost charged to expense in 1994 was approximately $324,000 (pre-tax).
In the first quarter of 1994, the Company offered and recorded an obligation related to a Voluntary Retirement Program (VRP). The VRP was accepted by 42 employees. The estimated benefit obligation for the VRP as of December 31, 1994 is about $4.5 million. This amount consists of pension benefits and postretirement medical benefits of $2.2 million and $2.3 million, respectively. Additionally, 32 employees accepted a Voluntary Severance Program (VSP) offered by the Company. Eligible employees had until April 22, 1994 to apply. The Company also announced a layoff of 20 employees on May 9, 1994. VSP and layoff obligations of $.8 million and $.2 million, respectively, were recorded in the second quarter of 1994. At December 31, 1994, the benefit obligation for the VSP was about $96,000. The VRP, VSP and layoff combined with attrition since mid-1993, yields a total work force reduction of approximately 14%. In the October 31, 1994 PSB Rate Order, the Company was allowed rate recovery of this restructuring cost over a five-year period. The unamortized balance of these costs was approximately $4.8 million at December 31, 1994.
Note 11 Income taxes
The components of Federal and state income tax expense are as follows (dollars in thousands):
Year Ended December 31 1994 1993 1992 Federal: Current $ 6,177 $ 2,751 $ 7,774 Deferred 3,417 7,893 2,042 Investment tax credits, net (391) (391) (391) ------- ------- ------- 9,203 10,253 9,425 ------- ------- ------- State: Current 1,710 406 1,987 Deferred 496 2,113 1,001 ------- ------- ------- 2,206 2,519 2,988 ------- ------- ------- Total Federal and state income taxes $11,409 $12,772 $12,413 ======= ======= =======
Federal and state income taxes charged (credited) to: Operating expenses $11,934 $12,496 $12,102 Other income (525) 276 311 ------- ------- ------- $11,409 $12,772 $12,413 ======= ======= =======
The principal components of deferred income tax expense for 1992 were additional depreciation for tax purposes of $3.9 million offset by $.9 million of contributions in aid of construction.
The principal items comprising the difference between the total income tax expense and the amount calculated by applying the statutory Federal income tax rate to income before tax are as follows (dollars in thousands):
Year Ended December 31 1994 1993 1992
Income before income tax $26,209 $34,064 $33,835 Federal statutory rate 35% 35% 34% Federal statutory tax expense $ 9,173 $11,922 $11,504 Increases (reductions) in taxes resulting from: Disallowed regulatory tax asset 1,641 - - Dividend received deduction (854) (995) (353) Deferred taxes on plant previously "flowed-through" 523 523 523 State income taxes net of Federal tax benefit 1,434 1,637 1,707 Investment credit amortization (391) (391) (391) Seabrook project 76 139 70 Book-to-return adjustments and other (193) (63) (647) ------- ------- ------- Total income tax expense provided $11,409 $12,772 $12,413 ======= ======= =======
The tax effects of temporary differences and tax carry forward that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below (dollars in thousands):
Year Ended December 31 1994 1993 Deferred tax assets Alternative minimum tax credit carry forward $ 900 $ 1,400 Non-deductible accruals and othe 4,682 4,186 Deferred compensation and pension 4,651 4,058 Environmental costs accrual 2,335 2,142 ------- ------- Total deferred tax assets 12,568 11,786 ------- ------- Deferred tax liabilities Property, plant and equipment 41,609 38,304 Net regulatory asset 12,217 13,806 Conservation and load management expenditures 7,664 5,123 Nuclear refueling costs 473 2,633 Other 3,315 3,948 ------- ------- Total deferred tax liabilities 65,278 63,814 ------- ------- Net deferred tax liability $52,710 $52,028 ======= =======
As a result of adopting SFAS No. 109 in 1993, the Company recognized additional net accumulated deferred income tax liabilities of approximately $15 million and a net corresponding regulatory asset from customers of approximately $15 million for future revenues that will be received when the temporary differences reverse and are settled in rates. As a result of the October 31, 1994 PSB Rate Order, during the fourth quarter of 1994, the Company recognized an additional $1.6 million of tax expense related primarily to a previous revenue agent review which were expected to be collected from customers through rates.
A valuation allowance has not been recorded, as the Company expects all deferred income tax assets will be utilized in the future.
The Company has an alternative minimum tax credit carry forward of $.9 million which is available to reduce future regular income taxes over an indefinite period.
Note 12 Retail Rate Increase
A PSB Rate Order dated October 31, 1994, allowed the Company a base retail rate increase of 4.27% or approximately $8.6 million effective with service rendered November 1, 1994. On December 14, 1994, the Company received an amended PSB Rate Order which allowed the Company a base retail rate increase of 5.07% or approximately $10.2 million. The Company had filed for an 8.9% or $17.9 million increase in its base retail rates in February 1994. The PSB Rate Order also lowered the allowed rate of return on the Company's common stock equity from 12% to 10%. The allowed return on equity is after deducting a .75% penalty based on the PSB's conclusions that there had been "mismanagement of power supply options" and because of "the Company's failed efforts to acquire all cost-effective energy efficiency resources." The Company disagrees with the PSB's conclusion.
As discussed in Note 11, the Company recorded an additional income tax provision of $1.6 million which it had previously expected to recover in rates but was disallowed in the Rate Order.
Note 13 Commitments and contingencies
The Company's power supply is acquired from a variety of sources including its own generating units, jointly owned units, long-term contracts and short-term purchases from a variety of sources. Through its investments in four nuclear generating companies, the Company is entitled to receive power from those nuclear units. See Note 2 for a discussion of the Company's obligations related to its investment in nuclear generating companies.
Under long-term contracts with various electric utilities in the region, the Company is purchasing certain percentages of the electrical output of production plants constructed and financed by those utilities. Such contracts obligate the Company to pay certain minimum annual amounts representing the Company's proportionate share of fixed costs, including debt service requirements (amounts necessary to retire the principal of and to pay the interest on the portion of the related long-term debt ascribed to the Company) whether or not the production plants are operating. The cost of power obtained under such long-term contracts, including payments required to be made when a production plant is not operating, is reflected as "Purchased power" in the Consolidated Statement of Income.
The Company purchases power from a coal-fired generating plant owned by Northeast Utilities (NU) under a thirty-year contract which expires April 30, 1998. Under this contract the Company is obligated to make capacity payments which amounted to approximately $3.7 million, $3.8 million and $4.3 million for 1992 through 1994, respectively. These capacity payments will vary over the contract period due to factors such as changes in NU's net investment and allowed rate of return.
The Company purchases power from several small power producers who own qualifying facilities under the Public Utility Regulatory Policies Act of 1978. These qualifying facilities produce energy using hydroelectric, wood, biomass, and refuse-burning generation. Under these long-term contracts, in 1994, the Company purchased 34.4 MW of which approximately 30.1 MW is associated with the Vermont Power Exchange and 3.9 MW with a New Hampshire/Vermont solid waste plant owned by Wheelabrator Claremont Company, L.P. The Company expects to purchase approximately 42 MW in each year 1995 through 1999. The total commitment in the next five years to purchase power from these qualifying facilities is approximately $105.9 million.
The Company will receive varying amounts of capacity and energy from two Hydro-Quebec contracts during the period 1995-2016. The contract between a group of Vermont utilities (Vermont Joint Owners) and Hydro-Quebec provides power over the entire period while a contract between the state of Vermont and Hydro-Quebec terminates on September 22, 1995. Additional contracts were negotiated between the Company and Hydro-Quebec which in effect reduce the amount of power the Company is required to purchase, as well as one signed in 1994 which reduces the cost to the Company.
The maximum net amount of capacity that the Company will purchase during the term of the agreements is 142.7 MW. The total commitment in the next five years to purchase power under these contracts is approximately $321 million, less approximately $112 million of power sellbacks, yielding a net cost of approximately $209 million.
Early in the Vermont Joint Owners contract, two sellback contracts were negotiated which reduced the net purchase of Hydro-Quebec power as well as delayed the purchase of about 24 MW of capacity and associated energy. In 1994, the Company negotiated a third sellback arrangement whereby the Company receives an effective discount on up to 70 MW of capacity in the 1996 contract year (declining to 30 MW in the 1999 contract year) in exchange for the right of Hydro-Quebec to reduce capacity deliveries by up to 50 MW beginning as early as 2004 until 2015, and the ability to reduce the amounts of energy delivered in up to five years beginning in 2000.
Joint-ownership The Company's ownership interests in jointly owned generating and transmission facilities are set forth in the table that follows and recorded in the Company's Consolidated Balance Sheet (dollars in thousands):
MW December 31 Ownership Entitlement 1994 1993 Generating plants: Wyman #4 1.78% 11 $ 3,338 $ 3,322 Joseph C. McNeil 20.00% 11 14,871 14,821 Millstone #3 1.73% 20 75,101 75,071 Highgate transmission facility 46.08% 12,775 12,586 -------- -------- 106,085 105,800 Accumulated depreciation 25,683 22,535 -------- -------- $ 80,402 $ 83,265 ======== ========
Wyman #4, an oil-fired generating plant, commenced commercial operation in December 1978. The Joseph C. McNeil wood, gas and oil-fired generating plant commenced commercial operation in June 1984 and the Millstone #3, a nuclear generating unit, commenced commercial operation in April 1986. The Highgate transmission interconnection with Canada was placed in service in September 1985. The Company's share of operating expenses for these facilities is included in the corresponding operating accounts on the Consolidated Statement of Income. Each participant in these facilities must provide for its own financing.
The Company is responsible for paying its ownership percentage of decommissioning costs for Millstone #3. Based on a 1992 study, total estimated obligation at December 31, 1994 was approximately $449 million and the funded obligation was about $76 million. The Company's share for the total obligation and funded obligation was approximately $7.8 million and $1.1 million, respectively.
Environmental The Company is engaged in various operations and activities which subject it to inspection and supervision by both state and Federal regulatory authorities including the United States Environmental Protection Agency (EPA) (hereinafter "environmental laws"). It is Company policy to comply with these environmental laws to the extent currently applicable and effective against it. The Company has implemented various procedures and internal controls to assess and assure compliance. If non-compliance is discovered, corrective action is taken. Based on these efforts and the oversight of those regulatory agencies having jurisdiction, the Company believes it conforms, in all material respects, with these environmental laws.
Company operations occasionally result in unavoidable and inadvertent spills or releases of regulated substances or materials, such as the rupture of a pole mounted transformer, broken hydraulic line, or other similar occurrences. When the Company learns of such spills and releases from ongoing operations, they are cleaned up to meet Federal and state requirements. Except as discussed in the following paragraphs, the Company is not aware of any instances where it has caused, permitted or suffered a release or spill on or about its properties or otherwise which will likely result in any material environmental liabilities to the Company.
The Company is an amalgamation of more than 100 predecessor companies engaged in various operations and activities prior to their being incorporated in the Company. At least two of these companies were involved in the production of gas from coal to sell and distribute to retail customers at three different locations. These activities were discontinued by the Company in the late 1940's or early 1950's. In addition, these predecessor companies and the Company itself may have historically engaged in other waste disposal activities, while legal and consistent with commercially accepted practices at the time, may not meet modern standards and thus represent potential liability. The Company continues to discover, investigate, evaluate, monitor and, where appropriate, remediate contaminated sites related to these historic activities. The Company's policy is to accrue a liability for those sites where costs for remediation, monitoring and other future activities are probable and can be reasonably estimated.
Based on these investigations and policies, coal tar deposits were discovered at the Company's Cleveland Avenue property located in the city of Rutland, a site where one of its predecessors operated a coal-gasification facility. Due to the presence of these deposits and uncertainties as to potential contamination migration off-site, the Company conducted studies to determine the magnitude and extent of the coal tar releases. The Company engaged a consultant to assist in evaluating clean-up methodologies and provide cost estimates. Those studies indicated the cost to remediate the site would be approximately $5 million. This was charged to expense in the fourth quarter of 1992. This was followed by an assessment of potential health, safety and ecological risks. Other site issues are still under evaluation. A final risk assessment report was completed and submitted to the state for review. Following state review, various remediation alternatives will be investigated. The Company was formally contacted by the EPA in January 1995 asking for written consent to conduct a site evaluation. The Company does not believe EPA's evaluation changes its potential liability so long as reasonable further progress is made in remediating the site. The Company has yet to determine whether insurance proceeds are available to offset the cost of any remediation required at this site.
The Company is currently investigating its potential liability regarding three former municipal landfills: the Bennington Landfill, the Parker Landfill, and the Trafton-Hoisington Landfill. The Bennington Landfill is a superfund site located in Bennington, Vermont. The Company was contacted in the winter of 1994 by counsel for a group of potentially responsible parties (PRP Group) who were performing an engineering evaluation and cost analysis (EE/CA) for the site under a settlement agreement with the EPA. The PRP Group threatened contribution litigation against the Company and others to recover an equitable share of the approximate $3 million the PRP Group had expended thus far on the EE/CA. Investigation by the Company thus far suggests that it is unlikely that it contributed a meaningful amount of hazardous substances, if any, to the site and thus would not be liable for a significant share of liability for the EE/CA expenses or site clean up. No litigation by the PRP Group has yet been initiated against the Company.
In July 1994, the EPA notified the Company that it had reviewed evidence which, in its opinion, indicated that the Company may have contributed to the environmental contamination at the site but that a full determination of its potential liability for the site had not been made. EPA, at that time, designated the Company a potentially interested party (PIP). Also in July 1994, the EPA notified the PRP Group, the Company and other PIPs that it was proposing a response action at the site with an estimated total present worth cost of approximately $9.5 million.
During November 1994, the Company was notified that EPA had information indicating that the Company was a PRP. The EPA letter also requested that the Company participate with other PRPs in the response action described above and further made a demand against the Company and other PRPs for reimbursement of approximately $.85 million in costs EPA had incurred in responding to conditions at the site.
The PRP Group is attempting to form a larger group of PRPs to undertake the remedial response, pay EPA response expenses and obtain reimbursement for the $3 million it spent on the EE/CA. Representatives of the Company have been in contact with EPA and the PRP Group and have evaluated the merits of participation with the larger group. The Company is entering into an agreement to become a part of the larger PRP Group and will also continue to work with EPA seeking a "de minimis" settlement.
While further investigation is necessary and is continuing, the results thus far suggest that the Company will defend any contribution action from the other PRPs and the EPA but will continue to explore settlement options which appear to be in the overall best interest of the Company. The Company has yet to determine whether insurance proceeds are available to offset potential costs for the remediation or other expenses which might be required by the Company at this site.
The Parker Landfill is a superfund site located in Lyndonville, Vermont. In 1989, the Company received an information request from the EPA seeking to determine if the Company sent any hazardous substances to the site. An investigation conducted at the time concluded general trash was occasionally sent to the site but the Company had not sent hazardous substances to the site. In May of 1994, the Company received a second request seeking additional information regarding disposal practices. A renewed investigation by the Company again concluded no significant amounts of hazardous substances were sent to the site. Last summer, EPA also announced its proposed preferred remedy for this site with an estimated total present net worth cost of $28.2 million. Final selection of a remedy is anticipated later this year. Thus far, the Company is considered a PIP, not a PRP, for the site. The Company has complied with the information request and will monitor EPA activities at the site.
The Trafton-Hoisington Landfill was a municipal and industrial landfill in the Town of Windsor, Vermont. The site is presently a state lead site although placement on the National Priorities List remains a possibility. The state of Vermont has reached an agreement with a small group of PRPs to conduct a site investigation. The Company was contacted by these PRPs seeking contribution toward the cost of the site investigation. The Company conducted an investigation and concluded no significant amounts of hazardous substances were sent to the site. The Company has advised the PRPs it will not voluntarily contribute under these circumstances.
At this time, the Company does not believe these sites represent the potential for a material adverse effect on its financial condition or results of operations but will continue to monitor activities at the sites.
The Company is not subject to any pending or threatened litigation with respect to any other sites where remediation expenses could be material, nor has the EPA or other state or Federal agency sought contribution from the Company for the study or remediation of any such sites.
Dividend restrictions The indentures relating to long-term debt and the Articles of Association contain certain restrictions on the payment of cash dividends on capital stock. Under the most restrictive of such provisions, approximately $45 million of retained earnings was not subject to dividend restriction at December 31, 1994.
Leases and support agreements The Company participated with other electric utilities in the construction of the Phase I Hydro-Quebec transmission facilities in northeastern Vermont, which were completed at a total cost of approximately $140 million. Under a support agreement relating to the Company's participation in the facilities, the Company is obligated to pay its 4.42% share of Phase I Hydro-Quebec capital costs over a 20-year recovery period through and including 2006. The Company also participated in the construction of Phase II Hydro-Quebec transmission facilities constructed throughout New England, which were placed in service in November 1990 with a total cost of approximately $487 million. Under a similar support agreement, the Company is obligated to pay its 5.132% share of Phase II Hydro-Quebec capital costs over a 25-year recovery period through and including 2015. All costs under these support agreements are recorded as purchased transmission expense in accordance with the Company's rate-making policies. Future minimum payments will be approximately $3.2 million for each year from 1995 through 2015 and will decline thereafter. The Company's percentage shares of the net capital cost of these facilities, totaling approximately, $21.6 million, are classified in the accompanying Consolidated Balance Sheet as "Utility Plant" and "Long-term Lease Arrangements" (current and non-current).
Minimum rental commitments of the Company under non-cancelable leases as of December 31, 1994, are not material. Total rental expense entering into the determination of net income, consisting principally of vehicle and equipment rentals, was approximately $3.0 million, $3.1 million and $3.3 million for the years 1992 through 1994, respectively.
Legal proceeding On December 30, 1994, the Company and its board of directors were named as defendants in a complaint filed in the United States District Court for the District of Vermont by three shareholders. The complaint alleges, among other things, (i) that F. Ray Keyser, Jr., Chairman of the Company's board of directors, violated Section 8 of the Clayton Act, 15 U.S.C. Subchapter 19, which precludes certain interlocking directorships, (ii) that Mr. Keyser violated his fiduciary duties to the Company's stockholders by acquiring and operating a series of businesses in competition with the Company without offering those business opportunities to the Company, (iii) that the remaining individual defendants violated their fiduciary duties to the Company's stockholders by failing to analyze, or to cause management to analyze, diversification into propane and fossil fuels, and by failing to make the Company an effective competitor of alternative fuel companies, and (iv) that the Company violated the applicable provision of the Vermont General Corporation Law by failing to provide a list of the Company's stockholders. The complaint seeks an unspecified amount of damages (including treble damages against Mr. Keyser), attorney's fees and costs, a list of the Company's stockholders, and a court order to enjoin the defendants from alleged continuing violations of the law. Each of the individual defendants and the Company itself deny the allegations against them and intend to vigorously defend the complaint.
Note 14 Non-recurring charge
In addition to the write-offs described in Notes 3 and 11 herein, during the fourth quarter of 1994, the Company also wrote-off approximately $2.9 million of costs associated with its proposed new headquarters office building which reduced after tax earnings by approximately $1.7 million.
Note 15 Unaudited quarterly financial information
The following quarterly financial information is unaudited and includes all adjustments consisting of normal recurring accruals which are, in the opinion of management, necessary for a fair statement of results of operations for such periods. Variations between quarters reflect the seasonal nature of the Company's business (dollars in thousands, except per share amounts):
Quarter Ended 12 Months March June September December Ended
Operating revenues $83,885 $57,684 $59,027 $76,562 $277,158 Operating income (loss) $14,367 $ (447) $ 368 $ 6,815 $ 21,103 Net income (loss) $12,608 $(2,003) $ (791) $ 4,986 $ 14,800 Earnings (loss) per share of common stock $1.04 $(.22) $(.11) $.38 $1.08
Operating revenues $85,319 $56,975 $60,994 $76,101 $279,389 Operating income $16,847 $ 260 $ 679 $ 8,260 $ 26,046 Net income (loss) $14,828 $ (920) $ (354) $ 7,738 $ 21,292 Earnings (loss) per share of common stock $1.26 $(.14) $(.09) $.61 $1.64
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
PART III
Item 10. Directors and Executive Officers of the Registrant.
The Company's Articles of Incorporation and By-Laws provide for the division of the Board of Directors into three classes having staggered terms of office. In accordance with the Company's By-Laws, the Board of Directors has fixed at ten (10) the number of Directors for the ensuing year. The Directors whose terms will expire at the 1995 Annual Meeting of Stockholders, consisting of the three nominees listed below, will stand for re-election to a three-year term expiring in 1998. Proxies will be voted (unless otherwise instructed) in favor of the election of the three nominees as indicated in the table below. While it is not anticipated that any of the persons listed will be unable to serve as a director, if that should occur the proxies will be voted for such other person or persons as the present Board of Directors shall determine.
The following table sets forth certain information regarding the three nominees for Director, as well as all Directors presently serving on the Board whose terms will expire after the 1995 Annual Meeting. Each of the individuals listed in the table has been employed by the firm or has had the occupation set forth under his or her name for the past five years. In general, the business experience of each of these persons during this time was typical of a person engaged in the principal occupation listed for each.
Served as Director Principal Occupation and Name and Age Since Business Experience
Nominees whose terms will expire in 1998:
Luther F. Hackett - 61 1979 President, Hackett, Valine & MacDonald, Inc., Burlington, Vermont (Insurance Agents)
F. Ray Keyser, Jr. - 67 1980 Chairman of the Board of Central Vermont Public Service Corporation, Of Counsel, Keyser, Crowley, Meub, Layden, Kulig & Sullivan, P.C. Rutland, Vermont (Lawyers)
Gordon P. Mills - 58 1980 Chairman, EHV-Weidmann Industries, Inc., St. Johnsbury, Vermont (Manufacturer of Electric Transformer Insulation)
Directors whose terms will expire in 1997:
Frederic H. Bertrand - 58 1984 Chairman of the Board and Chief Executive Officer, National Life Insurance Co. Montpelier, Vermont
Mary Alice McKenzie - 37 1992 President and Chief Executive Officer, John McKenzie Packing Co., Inc. Burlington, Vermont (Manufacturer of Meat Products)
Robert D. Stout - 68 1985 Retired President and Chief Executive Officer, Putnam Memorial Health Corporation, Bennington, Vermont Served as Director Principal Occupation and Name and Age Since Business Experience
Directors whose terms will expire in 1996:
Robert P. Bliss, Jr. - 71 1973 President, Bob Bliss, Ltd. St. Albans, Vermont (Insurance Industry Consultants)
Elizabeth Coleman - 57 1990 President, Bennington College, Bennington, Vermont
Preston Leete Smith - 64 1977 Chief Executive Officer, S-K-I Ltd., West Lebanon, New Hampshire (Ski Business)
Thomas C. Webb - 60 1986 President and Chief Executive Officer, Central Vermont Public Service Corporation, Rutland, Vermont
Executive Officers of the Registrant:
Name and Age Office Officer Since
Thomas C. Webb, 60 President and Chief Executive Officer 1985
Robert H. Young, 47 Executive Vice President and Chief Operating Officer 1987
Robert de R. Stein, 45 Senior Vice President-Energy Resources and External Markets 1988
Frederick S. Potter, 49 Vice President-Finance & Administration and Principal Financial Officer 1994
Jacquel-Anne Chouinard, 55 Vice President-Human Resources 1986
Thomas J. Hurcomb, 57 Vice President-Marketing and Public Affairs 1975
Robert G. Kirn, 43 Vice President-Engineering and Operations 1991
William J. Deehan, 42 Assistant Vice President-Rates and Economic Analysis 1991
Jonathan W. Booraem, 56 Treasurer 1984
Joseph M. Kraus, 40 Secretary and General Counsel 1987
James M. Pennington, 39 Controller and Principal Accounting Officer 1993
Mr. Webb joined the Company in 1985 as Executive Vice President - Finance and Administration and in 1986 was also designated Chief Executive Officer. He was elected Director, President and Chief Executive Officer on July 1, 1986.
Mr. Young joined the Company in 1987 as Vice President - Finance and Administration. Mr. Young was named Senior Vice President - Finance and Administration in 1988, and in 1993 was elected Executive Vice President and Chief Operating Officer.
Mr. Stein joined the Company in 1988 as Assistant Vice President - Energy Planning. Mr. Stein was elected Vice President - Energy Supply Planning and Engineering effective January 1, 1990, and Senior Vice President - Engineering and Energy Resources in 1993 and assumed his present position in 1994.
Mr. Potter joined the Company in 1994 and has served as Vice President - Finance and Administration and Principal Financial Officer since that time. From 1991-1994 he was Vice President at DQE, Inc. and President of its wholly owned subsidiary, Duquesne Enterprises, Inc. During 1989-1990 he was a senior investment banker with Bear, Stearns & Co. Inc.
Ms. Chouinard joined the Company in 1985 as Director - Human Resources. She was elected Assistant Vice President - Human Resources in 1986 and assumed her present position in 1988.
Mr. Hurcomb joined the Company in 1967 in the Marketing and Customer Service area. He was elected Vice President - External Affairs in 1975, and Vice President - Marketing and Public Affairs in 1993.
Mr. Kirn joined the Company in 1991 as Vice President - Division Operations and assumed his present position in 1994. From 1979 to 1991, he was employed by New York State Electric & Gas Corporation. He served as Operations Manager of the Lancaster Division Electric from 1988 until 1991.
Mr. Deehan joined the Company in 1985. Prior to being elected to his present position, he served as Director of Rate Administration and Forecasting.
Mr. Booraem has been with the Company since 1969. Prior to being elected Treasurer in 1984, he was Director of Finance & Planning.
Mr. Kraus joined the Company in 1981 as Assistant Corporate Counsel. He was named Associate Corporate Counsel in 1983 and Senior Corporate Counsel in 1987. He was also elected Corporate Secretary and Senior Corporate Counsel in 1987 and Corporate Secretary and General Counsel effective January 1, 1994.
Mr. Pennington joined the Company in 1989 as Director of Taxes. He was named Director of Taxes and Plant Accounting in 1990. Mr. Pennington was designated Acting Controller effective July 19, 1992, and was elected Controller and named Principal Accounting Officer in 1993.
The term of each officer is for one year or until a successor is elected.
Item 11. Executive Compensation.
The following table sets forth all cash compensation paid or to be paid by the Company and its subsidiaries, as well as the number of stock option awards earned during the last three fiscal years by the Company's Chief Executive Officer and the four other most highly compensated executive officers whose salary and bonus for services rendered to the Company and its subsidiaries in all capacities for 1994 exceeded $100,000.
I. Summary Compensation Table
Long Term Compensation Annual Compensation Awards - ------------------------------------------------------ ------------ (a) (b) (c) (d) (g) (i) Securities Underlying Option/ All Other Name and Principal Salary Bonus SARs Compensation Position Year ($) 1/ ($)2/ (#) ($) 3/ - ---------------------- ---- ------- ------ ------------ --------- A. Thomas C. Webb 1994 260,759 0 8,000/0 7,946 President and Chief 1993 248,755 67,183 8,000/0 12,453 Executive Officer 1992 244,694 73,000 6,000/0 17,850
B. Robert H. Young 1994 153,756 0 6,000/0 4,927 Executive Vice President 1993 141,769 35,995 6,000/0 4,533 and Chief Operating 1992 130,667 34,073 4,500/0 4,363 Officer
C. Robert de R. Stein 1994 119,606 0 4,500/0 4,873 Senior Vice President- 1993 114,677 16,804 4,500/0 3,988 Energy Resources and 1992 105,473 18,728 3,000/0 3,472 External Markets
D. Thomas J. Hurcomb 1994 104,115 0 3,000/0 4,534 Vice President 1993 98,382 15,606 3,000/0 4,996 Marketing and 1992 98,649 17,766 3,000/0 4,355 Public Affairs
E. Robert G. Kirn 1994 98,201 0 3,000/0 4,264 Vice President - 1993 93,736 15,750 3,000/0 3,574 Engineering and 1992 93,465 19,869 3,000/0 1,751 Operations
1/ - 1993 and 1994 include compensation deferred at the election of all executive officers named, and directors' retainers and fees earned from VELCO by Mr. Webb. - 1992 calendar year includes 53 pay periods. - Includes compensation for services performed by Mr. Webb for Vermont Yankee and by Mr. Stein for VELCO for which the Company was reimbursed.
2/ - Includes incentive bonuses awarded by Catamount Energy Corporation, a wholly owned subsidiary, in 1992 and 1993 as follows: For A: 1993 - $10,000, 1992 - $5,000, for B: 1993 - $10,000, 1992 - $5,000. - Includes relocation bonus for E: 1992 - $5,000.
3/ - The total amounts shown in this column for the last fiscal year are comprised as follows: (i) Company matching contributions to the Employee Savings and Investment Plan includes for A: $5,914; for B: $4,613; for C: $4,647; for D: $3,968; for E: $3,928. (ii) Taxable term cost on executive split-dollar insurance. (An insurance plan that gives both employer and employee an interest in the policy death benefit on the employee's life.) For A: $2,032; for B: $314; for C: $226; for D: $566; for E: $336.
Stock Options.
The following table sets forth stock options granted to the Company's Chief Executive Officer and the four other most highly compensated executive officers during 1994 under the Company's 1988 Stock Option Plan for Key Employees. Under SEC regulations, companies are required to project an estimate of appreciation of the underlying shares of stock during the option term. The Company has chosen the Black-Scholes model formula approved by the SEC. However, the ultimate value will depend on the market value of the Company's stock at a future date, which may or may not correspond to the projections below.
II. Options/SAR Grants Table
Option/SAR Grants in Last Fiscal Year
Grant Date Individual Grants Value - ------------------ ---------- ---------- -------- ------- ---------- % of Number of Total Securities Options/ Underlying SARs Options/ Granted to Exercise Grant SARs Employees Or Base Expira- Date Granted In Fiscal Price tion Present Name (#) 1/ Year ($/Sh) Date Value 2/ - ------------------ ---------- ---------- -------- ------- ---------- Thomas C. Webb 8,000/0 21.1% $18.4375 5/3/04 $13,920
Robert H. Young 6,000/0 15.8 18.4375 5/3/04 10,440
Robert de R. Stein 4,500/0 11.8 18.4375 5/3/04 7,830
Thomas J. Hurcomb 3,000/0 7.9 18.4375 5/3/04 5,220
Robert G. Kirn 3,000/0 7.9 18.4375 5/3/04 5,220
1/ A total of 38,000 shares were awarded to all plan participants in 1994. Stock Options are exercisable in whole or in part from the date of the grant for a period of ten years and one day.
2/ Per Black-Scholes model as certified by independent consultant. The assumptions used for the Model are as follows: Volatility- .201 based on quarterly prices for the period of 3/31/88 to 12/31/94; Risk free rate of return-7.2%; Dividend Yield-7.7% over period of 3/31/88 to 12/31/94; and Term of Exercise-10 years.
The following table sets forth stock options exercised by the Company's Chief Executive Officer and the four other most highly compensated executive officers during 1994, and the number and value of all unexercised options at year-end. The value of "in-the-money" options refers to options having an exercise price which is less than the market price of the Company's common stock on December 31, 1994.
III. Option/SAR Exercises and Year-end Value Table
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Value
(a) (b) (c) (d) (e) Number of Securities Value of Underlying Unexercised Unexercised In-the-Money Options/SARs Options/SARs At FY-End (#) FY-End ($) Shares Acquired Value Exercisable/ Exercisable/ Name on Exercise (#) Realized($)1/ Unexercisable Unexercisable - ------------------ --------------- ------------- ------------- -------------
Thomas C. Webb - - 22,000/0 $0/0
Robert H. Young 4,125 $7,391 16,500/0 0/0
Robert de R. Stein - - 19,500/0 0/0
Thomas J. Hurcomb - - 18,000/0 0/0
Robert G. Kirn - - 11,250/0 0/0
1/ The dollar values in columns (c) and (e) are calculated by determining the difference between the fair market value of the securities underlying the options and the exercise or base price of the options at exercise or fiscal year end, respectively.
Deferred Compensation Plan.
Employees of the Company who are officers are eligible to defer receipt of a portion of their compensation pursuant to the Company's Deferred Compensation Plan (the "Plan") for Officers. Also, certain of the Directors of the Company have elected to defer receipt of all or a portion of their fees under a similar plan for Directors.
Under the Plan approved effective January 1, 1990 Directors and Officers of the Company may elect to defer over a 5-year period receipt of a specified amount of compensation or fees otherwise currently payable to them until retirement at age 65 (age 70 for Directors), or until their death, disability, or resignation. Officers may receive a reduced benefit beginning at age 60 with 10 years of service. Amounts deferred are not currently taxable for state and federal income taxes. The benefit is equal to the compensation deferred plus interest credited by the Company. The plan is a defined contribution program under which the Company recovers any costs, including the cost of capital, through the proceeds of the supporting life insurance policies. In addition, if death of a Director occurs before age 70, an additional survivor benefit equal to the annual amount deferred will be paid to the beneficiary each year for fifteen years. This benefit is also financed by life insurance proceeds.
Pension Plan.
The Pension Plan of Central Vermont Public Service Corporation and Its Subsidiaries (the "Plan") is a defined benefit plan which covers employees, among others, who are officers. The Company pays the full cost of the Plan.
The table below shows the annual amounts payable under the present provisions of the Plan as amended through December 31, 1994, based on Final Average Earnings for various years of service, assuming the employee would retire at age 65 in 1995.
________ (1) Internal Revenue Code Section 401(a)(17) limits earnings used to calculate qualified plan benefits to $150,000 for 1994.
Final Average Earnings is the highest five-year average of consecutive years' Base Salary (item (c) from the Summary Compensation Table with the exclusion of Mr. Webb s retainer and fees from VELCO) over an employee's career with the Company.
The amounts above are payable for the life of the retiree only, and would be reduced on an actuarial basis if survivor options were chosen. In addition, no Social Security offset applies to amounts above.
The credited years of service at December 31, 1994 under the Plan for those individuals named in the Summary Compensation Table were as follows: Mr. Webb, 10 years; Mr. Young, 7 years, 6 months; Mr. Stein, 6 years, 7 months; Mr. Hurcomb, 27 years and Mr. Kirn, 3 years, 8 months.
Officers' Insurance and Supplemental Retirement Plan
The Officers' Insurance and Supplemental Retirement Plan (the "Plan") is designed to supplement the retirement benefits available to the Company's officers. The Plan is a part of the Company's overall strategy for attracting and maintaining top managerial talent in the utility industry. Under this Plan, the individuals named in the Summary Compensation Table are covered, while employed, by life insurance at the following multiple of salary: Mr. Webb, 4 times; Messrs. Young, Stein, Hurcomb and Kirn, 3 times.
Under the Plan, each officer is entitled to receive, upon his or her retirement at age 65, fifteen annual payments in amounts equal to a specified percentage of his or her final year's Base Salary (item (c) from the Summary Compensation Table with the exclusion of Mr. Webb s retainer and fees from VELCO). A reduced benefit is available at age 60 for officers who attain age 55 with ten years of service. A paid-up life insurance of $100,000 is also provided to vested retirees under this Plan.
The applicable percentages for the individuals named in Summary Compensation Table are as follows: Mr. Webb, 44.5%; Messrs. Young, Stein, Hurcomb and Kirn, 33%.
Shown below is the estimated Company provided benefit payable under the Plan for those individuals named in the Summary Compensation Table, assuming they were to retire at age 65:
Assumed Final Annual Base Pay 33% 44.5% --------------- ------ ------- $ $ $ --------------- ------ ------- 80,000 26,400 35,600 100,000 33,000 44,500 120,000 39,600 53,400 140,000 46,200 62,300 160,000 52,800 71,200 180,000 59,400 80,100 220,000 72,600 97,900 260,000 85,800 115,700
The Plan is financed through the Company's acquisition of corporate-owned life insurance.
Predecessor Deferred Compensation Plan.
Between 1986 and 1990, the Company allowed officers to defer receipt of compensation in return for fifteen annual payments of a defined benefit amount upon retirement. The Company will pay the difference, if any, between the defined benefit cost and the accumulated value of deferred compensation.
Shown below is the estimated Company-provided benefit, payable at age 65, for those individuals named in the Summary Compensation Table who elected to participate. Since these benefits do not apply to all of the named individuals, they have not been reflected in the foregoing pension table.
Annual Company- Provided Benefit Name Payable at Age 65 ----------- -----------------
Mr. Webb $29,800 Mr. Hurcomb 13,900
Employee Savings and Investment Plan.
Effective January 1, 1985 the Company adopted an Employee Savings and Investment Plan (the Plan ) (also known as a 401(k) Plan) which provides a means for eligible employees to accumulate savings and investment income without payment of current income taxes. Presently any employee of the Company who has completed at least one year of service, as defined in the Plan, is eligible to participate ( Participant ). An eligible employee who elects to participate in the Plan may authorize the Company to contribute to the Plan for his or her account between 1% and 15% of their pre-tax base compensation for each pay period. For 1994, the Plan limits the maximum annual deferral to $9,240 per Participant. This maximum is adjusted annually for inflation by the Internal Revenue Service. The Company matches 100% of the first 4% of the compensation the Participant contributes to the Plan. A Participant may direct the investment of his or her Plan account among five funds specified in the Plan and is at all times fully vested in his or her Plan account. Generally, distribution of employee contributions is deferred until the Participant's death, disability, retirement or other termination of employment, except in cases of financial hardship. Matching employer contributions, however, may be withdrawn by the Participant at any time and for any reason, provided either the amount withdrawn has been in the Plan for at least two years or the Participant has been a member of the Plan for at least 5 years. Such in-service withdrawals are generally subject to ordinary income tax and an additional 10% tax plus a mandatory 20% rollover tax withholding effective January 1, 1993. Distribution of Plan benefits may be in the form of cash, an annuity, or in certain circumstances, Common Stock of the Company. Amounts voluntarily deferred by the five highest paid executive officers are included in compensation listed in Item (c) of the Summary Compensation Table. Matching Company contributions credited to the Plan accounts of the individuals referred to during 1994 are set forth in Column 4, Item (i) in the Summary Compensation Table.
Contracts with Management.
The Company has entered into severance compensation agreements with Messrs. Webb, Young, Stein, Hurcomb, Kirn and six other officers of the Company. The agreements have a term of five years provision for renewal. They provide that in the event of termination of employment, or a significant change in employment status as defined in the agreement, within three years following a change in control of the Company, Messrs. Webb, Young, Stein, Hurcomb, Kirn and three other executive officers will receive 2.999 times and three other officers will receive two times their average annual compensation for the preceding five or fewer years of service and certain legal fees and expenses incurred as a result of termination of employment.
The provisions of the agreement do not apply if the officer retires, dies, or is disabled, voluntarily resigns, or is dismissed for cause. In exchange for agreeing to provide consulting services as requested by the Company for one year and refraining from working in competition with, or for a competitor of the Company for three years, the agreement permits continued participation in and retention of benefits under the Deferred Compensation Plan, Officers' Insurance and Supplemental Retirement Plans, and health and disability plans. The extent of these provisions depends on an individual's participation and circumstances, and is specified in each agreement. Those seven officers with less than 10 years of service would receive a payment actuarially equivalent to benefits received under the Company's pension plan at age 65 with ten years of service, less any benefit paid under the pension plan. The agreements also provide for the payment to officers of an amount sufficient to offset any federal excise tax on the termination payments under Section 4999 of the Internal Revenue Code. Non-qualified stock options not immediately exercisable will become exercisable in the event of a change of control of the Company as defined in the Plan.
A change of control occurs under the agreement when (1) any person, corporation, partnership or group acquires 20% or more of the combined voting power of the Company's outstanding securities; (2) if those members constituting a majority of the Directors at any given date no longer constitute a majority of the Directors at the end of a period of two consecutive years thereafter (unless the nomination of each new director was approved by a vote of at least two-thirds of the directors in office who were directors at the beginning of the period); or (3) if a third party acquires ownership or voting power of 10% or more of the outstanding voting securities of the Company, and subsequently is a "public utility holding company" within the meaning of the Public Utility Holding Company Act of 1935, or the Company loses its exemption from or is required to register under that Act.
During 1989, the Board also approved a severance plan in the event of a change of control for key managers of the Company not covered by the above plan. In the event of a change in control as described above and a subsequent discharge from employment within eighteen months for reason other than cause, thirty-two managers will receive a severance payment equal to one year's base salary, outplacement services, and coverage under the Company's medical plan for one year at Company expense.
The Board of Directors believes that such agreements protect the stockholders by ensuring officers and key managers can and will act in stockholders' best interests without regard to personal situations or concerns. The Board also believes that such agreements will better ensure retention and recruitment of high caliber officers and key managers.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The following table sets forth the number of shares of Common Stock of the Company beneficially owned by each director and nominee director, each of the executive officers named in the Summary Compensation Table and by all the directors, nominee directors and officers as a group as of January 31, 1995.
Shares of Common Stock Name Beneficially Owned (1)(2)(3)(4) -------------------- ----------------------
Frederic H. Bertrand 10,444 (5) Robert P. Bliss, Jr. 10,573 (6) Elizabeth Coleman 9,959 Luther F. Hackett 8,533 (7) Thomas J. Hurcomb 20,773 F. Ray Keyser, Jr. 14,226 (8) Robert G. Kirn 11,456 Mary Alice McKenzie 6,192 (9) Gordon P. Mills 44,606 (10) Preston Leete Smith 8,299 Robert de R. Stein 19,849 Robert D. Stout 11,531 Thomas C. Webb 35,290 Robert H. Young 17,410 All directors and officers as a group (20) 266,525
No Director, nominee for Director or Executive Officer owns any shares of the various classes of the Company's outstanding non-voting preferred stock.
(1) No Director, nominee for Director or executive officer owns beneficially in excess of 1% of CVPS' outstanding Common Stock, except as otherwise indicated in the footnotes to the table, each of the named individual possesses sole voting and investment power over the shares listed.
(2) Includes shares that the named individuals have a right to acquire pursuant to options granted under the 1988 and 1993 Stock Option Plans for Non-Employee Directors as follows: Messrs. Bertrand and Keyser, 9,000 shares; Messrs. Bliss, Mills and Stout, 7,500 shares; Ms. McKenzie and Mr. Smith, 6,000 shares; Ms. Coleman and Mr. Hackett, 4,500 shares.
(3) Includes shares that the named individuals have a right to acquire pursuant to options granted under the 1988 Stock Option Plan for Key Employees as follows: Mr. Hurcomb, 18,000 shares; Mr. Kirn, 11,250 shares; Mr. Stein, 19,500 shares; Mr. Webb, 22,000 shares; Mr. Young, 16,500 shares; and all Executive Officers as a group, 114,250 shares.
(4) Includes shares that the named individuals hold under the Company's Employee Savings and Investment and Employee Stock Ownership Plans as follows: Mr. Hurcomb, 2,759 shares; Mr. Webb, 8,790 shares; and Mr. Young, 310 shares.
(5) Includes 1,444 shares held jointly with his wife over which Mr. Bertrand has voting and investment power.
(6) Includes 150 shares held jointly with his wife over which Mr. Bliss has voting and investment power.
(7) Includes 1,500 shares owned by corporations over which Mr. Hackett has voting and investment power.
(8) Includes 1,476 shares held jointly with his wife and 3,750 shares held in a Keogh Trust over which Mr. Keyser has voting and investment power.
(9) Includes 150 shares held jointly with her husband over which Ms. McKenzie has voting and investment power.
(10) Includes 15,000 shares held in a pension trust over which Mr. Mills has voting and investment power.
The Company knows of no person, entity or group (within the meaning of Section 13(d)(3) of the Securities Exchange Act of 1934) which owns beneficially more than 5% of any class of the Company's outstanding equity securities.
Reports of Beneficial Ownership
Section 16(a) of the Securities Exchange Act of 1934 requires the Company's Directors and Officers to file reports of ownership and changes in ownership of Company securities with the Securities and Exchange Commission and to furnish the Company with copies of all such reports. In making this statement, the Company has relied on copies of reports that have been filed with the Commission.
Section 16(a) of the Securities Exchange Act of 1934 also requires directors, officers and persons who beneficially own more than ten percent (10%) of the Company's stock to file initial reports of ownership and subsequent reports of changes in ownership with the SEC and the NYSE. Based solely on a review of the copies of such reports prepared and filed with the Commission during 1994 by the Company's Executive Officers and Directors, and on written representations that no other reports were required the Company believes its Directors and Executive Officers have complied with all Section 16(a) filing requirements. The Company does not have a ten percent holder.
Item 13. Certain Relationships and Related Transactions.
None
Filed Herewith at Page PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a)1. The following financial statements for Central Vermont Public Service Corporation and its wholly owned subsidiaries are filed as part of this report: (See Item 8)
1.1 Consolidated Statement of Income, for each of the three years ended December 31, 1994
Consolidated Statement of Cash Flows, for each of the three years ended December 31, 1994
Consolidated Balance Sheet at December 31, 1994 and 1993
Consolidated Statement of Capitalization at December 31, 1994 and 1993
Consolidated Statement of Changes in Common Stock Equity for each of the three years ended December 31, 1994
Notes to Consolidated Financial Statements
(a)2. Financial Statement Schedules:
2.1 Central Vermont Public Service Corporation and its wholly owned subsidiaries:
Schedule II - Reserves for each of the three years ended December 31, 1994
Schedules not included have been omitted because they are not applicable or the required information is shown in the financial statements or notes thereto. Separate financial statements of the Registrant (which is primarily an operating company) have been omitted since they are consolidated only with those of totally held subsidiaries. Separate financial statements of subsidiary companies not consolidated have been omitted since, if considered in the aggregate, they would not constitute a significant subsidiary. Separate financial statements of 50% or less owned persons for which the investment is accounted for by the equity method by the Registrant have been omitted since, if considered in the aggregate, they would not constitute a significant investment.
(a)3. Exhibits (* denotes filed herewith)
Each document described below is incorporated by reference to the appropriate exhibit numbers and the Commission file numbers indicated in parantheses, unless the reference to the document is marked as follows:
* - Filed herewith.
Exhibit 3 Articles of Incorporation and By-Laws
* 3-1 By-Laws, as amended May 3, 1994.
3-2 Articles of Association, as amended August 11, 1992. (Exhibit No. 3-2, 1992 10-K, File No. 1-8222)
Exhibit 4 Instruments defining the rights of security holders, including Indentures
Incorporated herein by reference:
4-1 Mortgage dated October 1, 1929, between the Company and Old Colony Trust Company, Trustee, securing the Company's First Mortgage Bonds. (Exhibit B-3, File No. 2-2364)
4-2 Supplemental Indenture dated as of August 1, 1936, supplemental to 4-1. (Exhibit B-4, File No. 2-2364)
4-3 Copy of Supplemental Indenture dated as of November 15, 1943, supplemental to 4-1. (Exhibit B-3, File No. 2-5250)
4-4 Copy of Supplemental Indenture dated as of December 1, 1943, supplemental to 4-1. (Exhibit No. B-4, File No. 2-5250)
4-5 Copy of directors' resolutions adopted December 14, 1943, establishing the Series C Bonds and dealing with other related matters, supplemental to 4-1. (Exhibit B-5, File No. 2-5250)
4-6 Copy of Supplemental Indenture dated as of April 1, 1944 supplemental to 4-1. (Exhibit No. B-6, File No. 2-5466)
4-7 Copy of Supplemental Indenture dated as of February 1, 1945, supplemental to 4-1. (Exhibit 7.6, File No. 2-5615) (22-385)
4-8 Directors' resolutions adopted April 9, 1945, establishing the Series D Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 7.8, File No. 2-5615 (22-385)
4-9 Copy of Supplemental Indenture dated as of September 2, 1947, supplemental to 4-1. (Exhibit 7.9, File No. 2-7489)
4-10 Copy of Supplemental Indenture dated as of July 15, 1948, and directors' resolutions establishing the Series E Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 7.10, File No. 2-8388)
4-11 Copy of Supplemental Indenture dated as of May 1, 1950, and directors' resolutions establishing the Series F Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 7.11, File No. 2-8388)
4-12 Copy of Supplemental Indenture dated August 1, 1951, and and directors'resolutions, establishing the Series G Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 7.12, File No. 2-9073)
4-13 Copy of Supplemental Indenture dated May 1, 1952, and directors' resolutions, establishing the Series H Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 4.3.13, File No. 2-9613)
4-14 Copy of Supplemental Indenture dated as of July 10, 1953, supplemental to 4-1. (July, 1953 Form 8-K, File No. 1-8222)
4-15 Copy of Supplemental Indenture dated as of June 1, 1954, and directors' resolutions establishing the Series K Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 4.2.16, File No. 2-10959)
4-16 Copy of Supplemental Indenture dated as of February 1, 1957 and directors' resolutions establishing the Series L Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 4.2.16, File No. 2-13321)
4-17 Copy of Supplemental Indenture dated as of March 15, 1960, supplemental to 4-1. (March, 1960 Form 8-K, File No. 1-8222)
4-18 Copy of Supplemental Indenture dated as of March 1, 1962, supplemental to 4-1. (March, 1962 Form 8-K, File No. 1-8222)
4-19 Copy of Supplemental Indenture dated as of March 2, 1964, supplemental to 4-1. (March, 1964 Form 8-K, File No, 1-8222)
4-20 Copy of Supplemental Indenture dated as of March 1, 1965, and directors' resolutions establishing the Series M Bonds and dealing with other matters, supplemental to 4-1. (April, 1965 Form 8-K, File No. 1-8222)
4-21 Copy of Supplemental Indenture dated as of December 1, 1966, and directors' resolutions establishing the Series N Bonds and dealing with other matters, supplemental to 4-1. (January, 1967 Form 8-K, File No. 1-8222)
4-22 Copy of Supplemental Indenture dated as of December 1, 1967, and directors' resolutions establishing the Series O Bonds and dealing with other matters, supplemental to 4-1. (December, 1967 Form 8-K, File No. 1-8222)
4-23 Copy of Supplemental Indenture dated as of July 1, 1969, and directors' resolutions establishing the Series P Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B.23, July, 1969 Form 8-K, File No. 1-8222)
4-24 Copy of Supplemental Indenture dated as of December 1, 1969, and directors' resolutions establishing the Series Q Bonds January, and dealing with other matters, supplemental to 4-1. (Exhibit B.24, January, 1970 Form 8-K, File No. 1-8222)
4-25 Copy of Supplemental Indenture dated as of May 15, 1971, and directors' resolutions establishing the Series R Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B.25, May, 1971, Form 8-K, File No. 1-8222)
4-26 Copy of Supplemental Indenture dated as of April 15, 1973, and directors' resolutions establishing the Series S Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B.26, May, 1973, Form 8-K, File No. 1-8222)
4-27 Copy of Supplemental Indenture dated as of April 1, 1975, and directors' resolutions establishing the Series T Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B.27, April, 1975, Form 8-K, File No. 1-8222)
4-28 Copy of Supplemental Indenture dated as of April 1, 1977, modifying 4-1. (Exhibit 2.42, File No. 2-58621)
4-29 Copy of Supplemental Indenture dated as of July 29, 1977, and directors' resolutions establishing the Series U, V, W, and X Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 2.43, File No. 2-58621)
4-30 Copy of Thirtieth Supplemental Indenture dated as of September 15, 1978, and directors' resolutions establishing the Series Y Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B-30, 1980 Form 10-K, File No. 1-8222)
4-31 Copy of Thirty-first Supplemental Indenture dated as of September 1, 1979, and directors' resolutions establishing the Series Z Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B-31, 1980 Form 10-K, File No. 1-8222)
4-32 Copy of Thirty-second Supplemental Indenture dated as of June 1, 1981, and directors' resolutions establishing the Series AA Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B-32, 1981 Form 10-K, File No. 1-8222)
4-45 Copy of Thirty-third Supplemental Indenture dated as of August 15, 1983, and directors' resolutions establishing the Series BB Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B-45, 1983 Form 10-K, File No. 1-8222)
4-46 Copy of Bond Purchase Agreement between Merrill, Lynch, Pierce, Fenner & Smith, Inc., Underwriters and The Industrial Development Authority of the State of New Hampshire, issuer and Central Vermont Public Service Corporation. (Exhibit B-46, 1984 Form 10-K, File No. 1-8222)
4-47 Copy of Thirty-Fourth Supplemental Indenture dated as of January 15, 1985, and directors' resolutions establishing the Series CC Bonds and Series DD Bonds and matters connected therewith, supplemental to 4-1. (Exhibit B-47, 1985 Form 10-K, File No. 1-8222)
4-48 Copy of Bond Purchase Agreement among Connecticut Development Authority and Central Vermont Public Service Corporation with E. F. Hutton & Company Inc. dated December 11, 1985. (Exhibit B-48, 1985 Form 10-K, File No. 1-8222)
4-49 Stock-Purchase Agreement between Vermont Electric Power Company, Inc. and the Company dated August 11, 1986 relative to purchase of Class C Preferred Stock. (Exhibit B-49, 1986 Form 10-K, File No. 1-8222)
4-50 Copy of Thirty-Fifth Supplemental Indenture dated as of December 15, 1989 and directors' resolutions establishing the Series EE, Series FF and Series GG Bonds and matters connected therewith, supplemental to 4-1. (Exhibit 4-50, 1989 Form 10-K, File No. 1-8222)
4-51 Copy of Thirty-Sixth Supplemental Indenture dated as of December 10, 1990 and directors' resolutions establishing the Series HH Bonds and matters connected therewith, supplemental to 4-1. (Exhibit 4-51, 1990 Form 10-K, File No. 1-8222)
4-52 Copy of Thirty-Seventh Supplemental Indenture dated December 10, 1991 and directors' resolutions establishing the Series JJ Bonds and matters connected therewith, supplemental to 4-1. (Exhibit 4-52, 1991 Form 10-K, File No. 1-8222)
4-53 Copy of Thirty-Eight Supplemental Indenture dated December 10, 1993 establishing Series KK, LL, MM, NN, OO supplemental to B-1 (Exhibit 4-53, 1993 Form 10-K, File No. 1-8222)
Exhibit 10 Material Contracts (*Denotes filed herewith)
Incorporated herein by reference:
10.l Copy of firm power Contract dated August 29, 1958, and supplements thereto dated September 19, 1958, October 7, 1958, and October 1, 1960, between the Company and the State of Vermont (the "State"). (Exhibit C-1, File No. 2-17184)
10.1.1 Agreement setting out Supplemental NEPOOL Understandings dated as of April 2, 1973. (Exhibit C-22, File No. 5-50198)
10.2 Copy of Transmission Contract dated June 13, 1957, between Velco and the State, relating to transmission of power. (Exhibit 10.2, 1993 Form 10-K, File No. 1-8222)
10.2.1 Copy of letter agreement dated August 4, 1961, between Velco and the State. (Exhibit C-3, File No. 2-26485)
10.2.2 Amendment dated September 23, 1969. (Exhibit C-4, File No. 2-38161)
10.2.3 Amendment dated March 12, 1980. (Exhibit C-92, 1982 Form 10-K, File No. 1-8222)
10.2.4 Amendment dated September 24, 1980. (Exhibit C-93, 1982 Form 10-K, File No. 1-8222)
10.3 Copy of subtransmission contract dated August 29, 1958, between Velco and the Company (there are seven similar contracts between Velco and other utilities). (Exhibit 10.3, 1993 Form 10-K, Form No. 1-8222)
10.3.1 Copies of Amendments dated September 7, 196l, November 2, 1967, March 22, 1968, and October 29, 1968. (Exhibit C-6, File No. 2-32917)
10.3.2 Amendment dated December 1, 1972. (Exhibit 10.3.2, 1993 Form 10-K, File No. 1-8222)
10.4 Copy of Three-Party Agreement dated September 25, 1957, between the Company, Green Mountain and Velco. (Exhibit C-7, File No. 2-17184)
10.4.1 Superseding Three Party Power Agreement dated January 1, 1990. (Exhibit 10-201, 1990 Form 10-K, File No. 1-8222)
10.4.2 Agreement Amending Superseding Three Party Power Agreement dated May 1, 1991. (Exhibit 10.4.2, 1991 Form 10-K, File No. 1-8222)
10.5 Copy of firm power Contract dated December 29, 1961, between the Company and the State, relating to purchase of Niagara Project power. (Exhibit C-8, File No. 2-26485)
10.5.1 Amendment effective as of January 1, 1980. (Exhibit 10.5.1, 1993 Form 10-K, File No. 1-8222)
10.6 Copy of agreement dated July 16, 1966, and letter supplement dated July 16, 1966, between Velco and Public Service Company of New Hampshire relating to purchase of single unit power from Merrimack II. (Exhibit C-9, File No. 2-26485)
10.6.1 Copy of Letter Agreement dated July 10, 1968, modifying Exhibit A. Exhibit C-10, File No. 2-32917)
10.7 Copy of Capital Funds Agreement between the Company and Vermont Yankee dated as of February 1, 1968. (Exhibit C-11, File No. 70-4611)
10.7.1 Copy of Amendment dated March 12, 1968. (Exhibit C-12, File No. 70-4611)
* 10.7.2 Copy of Amendment dated September 1, 1993
10.8 Copy of Power Contract between the Company and Vermont Yankee dated as of February 1, 1968. (Exhibit C-13, File No. 70-4591)
10.8.1 Amendment dated April 15, 1983. (10.8.1, 1993 Form 10-K, File No. 1-8222)
10.8.2 Copy of Additional Power Contract dated February 1, 1984. (Exhibit C-123, 1984 Form 10-K, File No. 1-8222)
10.8.3 Amendment No. 3 to Vermont Yankee Power Contract, dated April 24, 1985. (Exhibit 10-144, 1986 Form 10-K, File No. 1-8222)
10.8.4 Amendment No. 4 to Vermont Yankee Power Contract, dated June 1, 1985. (Exhibit 10-145, 1986 Form 10-K, File No. 1-8222)
10.8.5 Amendment No. 5 dated May 6, 1988. (Exhibit 10-179, 1988 Form 10-K, File No. 1-8222)
10.8.6 Amendment No. 6 dated May 6, 1988. (Exhibit 10-180, 1988 Form 10-K, File No. 1-8222)
10.8.7 Amendment No. 7 dated June 15, 1989. (Exhibit 10-195, 1989 Form 10-K, File No. 1-8222)
10.9 Copy of Capital Funds Agreement between the Company and Maine Yankee dated as of May 20, 1968. (Exhibit C-14, File No. 70-4658)
10.9.1 Amendment No. 1 dated August 1, 1985. (Exhibit C-125, 1984 Form 10-K, File No. 1-8222)
10.10 Copy of Power Contract between the Company and Maine Yankee dated as of May 20, 1968. (Exhibit C-15, File No. 70-4658)
10.10.1 Amendment No. 1 dated March 1, 1984. (Exhibit C-112, 1984 Form 10-K, File No. 1-8222)
10.10.2 Amendment No. 2 effective January 1, 1984. (Exhibit C-113, 1984 Form 10-K, File No. 1-8222)
10.10.3 Amendment No. 3 dated October 1, 1984. (Exhibit C-114, 1984 Form 10-K, File No. 1-8222)
10.10.4 Additional Power Contract dated February 1, 1984. (Exhibit C-126, 1985 Form 10-K, File No. 1-8222)
10.11 Copy of Agreement dated January 17, 1968, between Velco and Public Service Company of New Hampshire relating to purchase of additional unit power from Merrimack II. (Exhibit C-16, File No. 2-32917)
10.12 Copy of Agreement dated February 10, 1968 between the Company and Velco relating to purchase by Company of Merrimack II unit power. (There are 25 similar agreements between Velco and other utilities.) (Exhibit C-17, File No. 2-32917)
10.13 Copy of Three-Party Power Agreement dated as of November 21, 1969, among the Company, Velco, and Green Mountain relating to purchase and sale of power from Vermont Yankee Nuclear Power Corporation. (Exhibit C-18, File No. 2-38161)
10.13.1 Amendment dated June 1, 1981. (Exhibit 10.13.1, 1993 Form 10-K, File No. 1-8222)
10.14 Copy of Three-Party Transmission Agreement dated as of November 21, 1969, among the Company, Velco, and Green Mountain providing for transmission of power from Vermont Yankee Nuclear Power Corporation. (Exhibit C-19, File No. 2-38161)
10.14.1 Amendment dated June 1, 1981. (Exhibit 10.14.1, 1993 Form 10-K, File No. 1-8222)
10.15 Copy of Stockholders Agreement dated September 25, 1957, between the Company, Velco, Green Mountain and Citizens Utilities Company. (Exhibit No. C-20, File No. 70-3558)
10.16 New England Power Pool Agreement dated as of September 1, 1971, as amended to November 1, 1975. (Exhibit C-21, File No. 2-55385)
10.16.1 Amendment dated December 31, 1976. (Exhibit 10.16.1 1993 Form 10-K, File No. 1-8222)
10.16.2 Amendment dated January 23, 1977. (Exhibit 10.16.2, 1993 Form 10-K, File No. 1-8222)
10.16.3 Amendment dated July 1, 1977. (Exhibit 10.16.3, 1993 Form 10-K, File No. 1-8222)
10.16.4 Amendment dated August 1, 1977. (Exhibit 10.16.4, 1993 Form 10-K, File No. 1-8222)
10.16.5 Amendment dated August 15, 1978. (Exhibit 10.16.5, 1993 Form 10-K, File No. 1-8222)
10.16.6 Amendment dated January 31, 1979. (Exhibit 10.16.6, 1993 Form 10-K, File No. 1-8222)
10.16.7 Amendment dated Feburary 1, 1980. (Exhibit 10.16.7, 1993 Form 10-K, File No. 1-8222)
10.16.8 Amendment dated December 31, 1976. (Exhibit 10.16.8, 1993 Form 10-K, File No. 1-8222)
10.16.9 Amendment dated January 31, 1977. (Exhibit 10.16.9, 1993 Form 10-K, File No. 1-8222)
10.16.10 Amendment dated July 1, 1977. (Exhibit 10.16.10, 1993 Form 10-K, File No. 1-8222)
10.16.11 Amendment dated August 1, 1977. (Exhibit 10.16.11, 1993 Form 10-K, File No. 1-8222)
10.16.12 Amendment dated August 15, 1978. (Exhibit 10.16.12, 1993 Form 10-K, File No. 1-8222)
10.16.13 Amendment dated January 31, 1980. (Exhibit 10.16.13, 1993 Form 10-K, File No. 1-8222)
10.16.14 Amendment dated February 1, 1980. (Exhibit 10.16.14, 1993 Form 10-K, File No. 1-8222)
10.16.15 Amendment dated September 1, 1981. (Exhibit 10.16.15, 1993 Form 10-K, File No. 1-8222)
10.16.16 Amendment dated December 1, 1981. (Exhibit 10.16.16, 1993 Form 10-K, File No. 1-8222)
10.16.17 Amendment dated June 15, 1983. (Exhibit 10.16.17, 1993 Form 10-K, File No. 1-8222)
10.16.18 Amendment dated September 1, 1985. (Exhibit 10-160, 1986 Form 10-K, File No. 1-8222)
10.16.19 Amendment dated April 30, 1987. (Exhibit 10-172, 1987 Form 10-K, File No. 1-8222)
10.16.20 Amendment dated March 1, 1988. (Exhibit 10-178, 1988 Form 10-K, File No. 1-8222)
10.16.21 Amendment dated March 15, 1989. (Exhibit 10-194, 1989 Form 10-K, File No. 1-8222)
10.16.22 Amendment dated October 1, 1990. (Exhibit 10-203, 1990 Form 10-K, File No. 1-8222)
10.16.23 Amendment dated September 15, 1992. (Exhibit 10.16.23, 1992 Form 10-K, File No. 1-8222)
10.16.24 Amendment dated May 1, 1993. (Exhibit 10.16.24, 1993 Form 10-K, File No. 1-8222)
10.16.25 Amendment dated June 1, 1993. (Exhibit 10.16.25, 1993 Form 10-K, File No. 1-8222)
* 10.16.26 Amendment dated June 1, 1994.
10.17 Agreement dated October 13, 1972, for Joint Ownership, Construction and Operation of Pilgrim Unit No. 2 among Boston Edison Company and other utilities, including the Company. (Exhibit C-23, File No. 2-45990)
10.17.1 Amendments dated September 20, 1973, and September 15, 1974. (Exhibit C-24, File No. 2-51999)
10.17.2 Amendment dated December 1, 1974. (Exhibit C-25, File No. 2-54449)
10.17.3 Amendent dated February 15, 1975. (Exhibit C-26, File No. 2-53819)
10.17.4 Amendment dated April 30, 1975. (Exhibit C-27, File No. 2-53819)
10.17.5 Amendment dated as of June 30, 1975. (Exhibit C-28, File No. 2-54449)
10.17.6 Instrument of Transfer dated as of October 1, 1974, assigning partial interest from the Company to Green Mountain Power Corporation. (Exhibit C-29, File No. 2-52177)
10.17.7 Instrument of Transfer dated as of January 17, 1975, assigning a partial interest from the Company to the Burlington Electric Department. (Exhibit C-30, File No. 2-55458)
10.17.8 Addendum dated as of October 1, 1974 by which Green Mountain Power Corporation became a party thereto. (Exhibit C-31, File No. 2-52177)
10.17.9 Addendum dated as of January 17, 1975 by which the Burlington Electric Department became a party thereto. (Exhibit C-32, File No. 2-55450)
10.17.10 Amendment 23 dated as of 1975. (Exhibit C-50, 1975 Form 10-K, File No. 1-8222)
10.18 Agreement for Sharing Costs Associated with Pilgrim Unit No.2 Transmission dated October 13, 1972, among Boston Edison Company and other utilities including the Company. (Exhibit C-33, File No. 2-45990)
10.18.1 Addendum dated as of October 1, 1974, by which Green Mountain Power Corporation became a party thereto. (Exhibit C-34, File No. 2-52177)
10.18.2 Addendum dated as of January 17, 1975, by which Burlington Electric Department became a party thereto. (Exhibit C-35, File No. 2-55458)
10.19 Agreement dated as of May 1, 1973, for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units among Public Service Company of New Hampshire and other utilities, including Velco. (Exhibit C-36, File No. 2-48966)
10.19.1 Amendments dated May 24, 1974, June 21, 1974, September 25, 1974, October 25, l974, and January 31, 1975. (Exhibit C-37, File No. 2-53674)
10.19.2 Instrument of Transfer dated September 27, 1974, assigning partial interest from Velco to the Company. (Exhibit C-38, File No. 2-52177)
10.19.3 Amendments dated May 24, 1974, June 21, 1974, and September 25, 1974. (Exhibit C-81, File No. 2-51999)
10.19.4 Amendments dated October 25, 1974 and January 31, 1975. (Exhibit C-82, File No. 2-54646)
10.19.5 Sixth Amendment dated as of April 18, 1979. (Exhibit C-83, File No. 2-64294)
10.19.6 Seventh Amendment dated as of April 18, 1979. (Exhibit C-84, File No. 2-64294)
10.19.7 Eighth Amendment dated as of April 25, 1979. (Exhibit C-85, File No. 2-64815)
10.19.8 Ninth Amendment dated as of June 8, 1979. (Exhibit C-86, File No. 2-64815)
10.19.9 Tenth Amendment dated as of October 10, 1979. (Exhibit C-87, File No. 2-66334 )
10.19.10 Eleventh Amendment dated as of December 15, 1979. (Exhibit C-88, File No.2-66492)
10.19.11 Twelfth Amendment dated as of June 16, 1980. (Exhibit C-89, File No. 2-68168)
10.19.12 Thirteenth Amendment dated as of December 31, 1980. (Exhibit C-90, File No. 2-70579)
10.19.13 Fourteenth Amendment dated as of June 1, 1982.(Exhibit C-104, 1982 Form 10-K, File No. 1-8222)
10.19.14 Fifteenth Amendment dated April 27, 1984. (Exhibit 10-134, 1986 Form 10-K, File No. 1-8222)
10.19.15 Sixteenth Amendment dated June 15, 1984. (Exhibit 10-135, 1986 Form 10-K, File No. 1-8222)
10.19.16 Seventeenth Amendment dated March 8, 1985. (Exhibit 10-136, 1986 Form 10-K, File No. 1-8222)
10.19.17 Eighteenth Amendment dated March 14, 1986. (Exhibit 10-137, 1986 Form 10-K, File No. 1-8222)
10.19.18 Nineteenth Amendment dated May 1, 1986. (Exhibit 10-138, 1986 Form 10-K, File No. 1-8222)
10.19.19 Twentieth Amendment dated September 19, 1986. (Exhibit 10-139, 1986 Form 10-K, File No. 1-8222)
10.19.20 Amendment No. 22 dated January 13, 1989. (Exhibit 10-193, 1989 Form 10-K, File No. 1-8222)
10.20 Transmission Support Agreement dated as of May 1, 1973, among Public Service Company of New Hampshire and other utilities, including Velco, with respect to New Hampshire Nuclear Units. (Exhibit C-39, File No. 248966)
10.21 Sharing Agreement - 1979 Connecticut Nuclear Unit dated September 1, 1973, to which the Company is a party. (Exhibit C-40, File No. 2-50142)
10.21.1 Amendment dated as of August 1, 1974. (Exhibit C-41, File No. 2-51999)
10.21.2 Instrument of Transfer dated as of February 28, 1974, transferring partial interest from the Company to Green Mountain. (Exhibit C-42, File No. 2-52177)
10.21.3 Instrument of Transfer dated January 17, 1975, transferring a partial interest from the Company to Burlington Electric Department. (Exhibit C-43, File No. 2-55458)
10.21.4 Amendment dated May 11, 1984. (Exhibit C-110, 1984 Form 10-K, File No. 1-8222)
10.22 Preliminary Agreement dated as of July 5, 1974, with respect to 1981 Montague Nuclear Generating Units. (Exhibit C-44, File No. 2-51733)
10.22.1 Amendment dated June 30, 1975. (Exhibit C-45, File No. 2-54449)
10.23 Agreement for Joint Ownership, Construction and Operation of William F. Wyman Unit No. 4 dated November 1, 1974, among Central Maine Power Company and other utilities including the Company. (Exhibit C-46, File No. 2-52900)
10.23.1 Amendment dated as of June 30, 1975. (Exhibit C-47, File No. 2-55458)
10.23.2 Instrument of Transfer dated July 30, 1975, assigning a partial interest from Velco to the Company. (Exhibit C-48, File No. 2-55458)
10.24 Transmission Agreement dated November 1, 1974, among Central Maine Power Company and other utilities including the Company with respect to William F. Wyman Unit No. 4. (Exhibit C-49, File No. 2-54449)
10.25 Copy of Power Contract between the Company and Yankee Atomic dated as of June 30, 1959. (Exhibit C-61, 1981 Form 10-K, File No. 1-8222)
10.25.1 Revision dated April 1, 1975. (Exhibit C-61, 1981 Form 10-K, File No. 1-8222)
10.25.2 Amendment dated May 6, 1988. (Exhibit 10-181, 1988 Form 10-K, File No. 1-8222)
10.25.3 Amendment dated June 26, 1989. (Exhibit 10-196, 1989 Form 10-K, File No. 1-8222)
10.25.4 Amendment dated July 1, 1989. (Exhibit 10-197, 1989 Form 10-K, File No. 1-8222)
10.25.5 Amendment dated February 1, 1992 (Exhibit 10.25.5, 1992 Form 10-K, File No. 1-8222)
10.26 Copy of Transmission Contract between the Company and Yankee Atomic dated as of June 30, 1959. (Exhibit C-63, 1981 Form 10-K, File No. 1-8222)
10.27 Copy of Power Contract between the Company and Connecticut Yankee dated as of June 1, 1964. (Exhibit C-64, 1981 Form 10-K, File No. 1-8222)
10.27.1 Supplementary Power Contract dated March 1, 1978. (Exhibit C-94, 1982 Form 10-K, File No. 1-8222)
10.27.2 Amendment dated August 22, 1980. (Exhibit C-95, 1982 Form 10-K, File No. 1-8222)
10.27.3 Amendment dated October 15, 1982. (Exhibit C-96, 1982 Form 10-K, File No. 1-8222)
10.27.4 Second Supplementary Power Contract dated April 30, 1984. (Exhibit C-115, 1984 Form 10-K, File No. 1-8222)
10.27.5 Additional Power Contract dated April 30, 1984. (Exhibit C-116, 1984 Form 10-K, File No. 1-8222)
10.28 Copy of Transmission Contract between the Company and Connecticut Yankee dated as of July 1, 1964. (Exhibit C-65, 1981 Form 10-K, File No. 1-8222)
10.29 Copy of Capital Funds Agreement between the Company and Connecticut Yankee dated as of July 1, 1964. (Exhibit C-66, 1981 Form 10-K, File No. 1-8222)
10.29.1 Copy of Capital Funds Agreement between the Company and Connecticut Yankee dated as of September 1, 1964. (Exhibit C-67, 1981 Form 10-K, File No. 1-8222)
10.30 Copy of Five-Year Capital Contribution Agreement between the Company and Connecticut Yankee dated as of November 1, 1980. (Exhibit C-68, 1981 Form 10-K, File No. 1-8222)
10.31 Form of Guarantee Agreement dated as of November 7, 1981, among certain banks, Connecticut Yankee and the Company, relating to revolving credit notes of Connecticut Yankee. (Exhibit C-69, 1981 Form 10-K, File No. 1-8222)
10.32 Form of Guarantee Agreement dated as of November 13, 1981, between The Connecticut Bank and Trust Company, as Trustee, and the Company, relating to debentures of Connecticut Yankee. (Exhibit C-70, 1981 Form 10-K, File No. 1-8222)
10.33 Form of Guarantee Agreement dated as of November 5, 1981, between Bankers Trust Company, as Trustee of the Vernon Energy Trust, and the Company, relating to Vermont Yankee Nuclear Fuel Sale Agreement. (Exhibit C-71, 1981 Form 10-K, File No. 1-8222)
10.34 Preliminary Vermont Support Agreement re Quebec Interconnection between Velco and among seventeen Vermont Utilities dated May 1, 1981. (Exhibit C-97, 1982 Form 10-K, File No. 1-8222)
10.34.1 Amendment dated June 1, 1982. (Exhibit C-98, 1982 Form 10-K, File No. 1-8222)
10.35 Vermont Participation Agreement for Quebec Interconnection between Velco and among seventeen Vermont Utilities dated July 15, 1982. (Exhibit C-99, 1982 Form 10-K, File No. 1-8222)
10.35.1 Amendment No. 1 dated January 1, 1986. (Exhibit C-132, 1986 Form 10-K, File No. 1-8222)
10.36 Vermont Electric Transmission Company Capital Funds Support Agreement between Velco and among sixteen Vermont Utilities dated July 15, 1982. (Exhibit C-100, 1982 Form 10-K, File No. 1-8222)
10.37 Vermont Transmission Line Support Agreement, Vermont Electric Transmission Company and twenty New England Utilities dated December 1, 1981, as amended by Amendment No. 1 dated June 1, 1982, and by Amendment No. 2 dated November 1, 1982. (Exhibit C-101, 1982 Form 10-K, File No. 1-8222)
10.37.1 Amendment No. 3 dated January 1, 1986. (Exhibit 10-149, 1986 Form 10-K, File No. 1-8222)
10.38 Phase 1 Terminal Facility Support Agreement between New England Electric Transmission Corporation and twenty New England Utilities dated December 1, 1981, as amended by Amendment No. 1 dated as of June 1, 1982 and by Amendment No. 2 dated as of November 1, 1982. (Exhibit C-102, 1982 Form 10-K, File No. 1-8222)
10.39 Power Purchase Agreement between Velco and CVPS dated June 1, 1981. (Exhibit C-103, 1982 Form 10-K, File No. 1-8222)
10.40 Agreement for Joint Ownership, Construction and Operation of the Joseph C. McNeil Generating Station by and between City of Burlington Electric Department, Central Vermont Realty, Inc. and Vermont Public Power Supply Authority dated May 14, 1982. (Exhibit C-107, 1983 Form 10-K, File No. 1-8222)
10.40.1 Amendment No. 1 dated October 5, 1982. (Exhibit C-108, 1983 Form 10-K, File No. 1-8222)
10.40.2 Amendment No. 2 dated December 30, 1983. (Exhibit C-109, 1983 Form 10-K, File No. 1-8222)
10.40.3 Amendment No. 3 dated January 10, 1984. (Exhibit 10-143, 1986 Form 10-K, File No. 1-8222)
10.41 Transmission Service Contract between Central Vermont Public Service Corporation and The Vermont Electric Generation & Transmission Cooperative, Inc. dated May 14, 1984. (Exhibit C-111, 1984 Form 10-K, File No. 1-8222)
10.42 Copy of Highgate Transmission Interconnection Preliminary Support Agreement dated April 9, 1984. (Exhibit C-117, 1984 Form 10-K, File No. 1-8222)
10.43 Copy of Allocation Contract for Hydro-Quebec Firm Power dated July 25, 1984. (Exhibit C-118, 1984 Form 10-K, File No. 1-8222)
10.43.1 Tertiary Energy for Testing of the Highgate HVDC Station Agreement, dated September 20, 1985. (Exhibit C-129, 1985 Form 10-K, File No. 1-8222)
10.44 Copy of Highgate Operating and Management Agreement dated August 1, 1984. (Exhibit C-119, 1986 Form 10-K, File No. 1-8222)
10.44.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-152, 1986 Form 10-K, File No. 1-8222)
10.44.2 Amendment No. 2 dated November 13, 1986. (Exhibit 10-167, 1987 Form 10-K, File No. 1-8222)
10.44.3 Amendment No. 3 dated January 1, 1987. (Exhibit 10-168, 1987 Form 10-K, File No. 1-8222)
10.45 Copy of Highgate Construction Agreement dated August 1, 1984. (Exhibit C-120, 1984 Form 10-K, File No. 1-8222)
10.45.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-151, 1986 Form 10-K, File No. 1-8222)
10.46 Copy of Agreement for Joint Ownership, Construction and Operation of the Highgate Transmission Interconnection. (Exhibit C-121, 1984 Form 10-K, File No. 1-8222)
10.46.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-153, 1986 Form 10-K, File No. 1-8222)
10.46.2 Amendment No. 2 dated April 18, 1985. (Exhibit 10-154, 1986 Form 10-K, File No. 1-8222)
10.46.3 Amendment No. 3 dated February 12, 1986. (Exhibit 10-155, 1986 Form 10-K, File No. 1-8222)
10.46.4 Amendment No. 4 dated November 13, 1986. (Exhibit 10-169, 1987 Form 10-K, File No. 1-8222)
10.46.5 Amendment No. 5 and Restatement of Agreement dated January 1, 1987. (Exhibit 10-170, 1987 Form 10-K, File No. 1-8222)
10.47 Copy of the Highgate Transmission Agreement dated August 1, 1984. (Exhibit C-122, 1984 Form 10-K, File No. 1-8222)
10.48 Copy of Preliminary Vermont Support Agreement Re: Quebec Interconnection - Phase II dated September 1, 1984. (Exhibit C-124, 1984 Form 10-K, File No. 1-8222)
10.48.1 First Amendment dated March 1, 1985. (Exhibit C-127, 1985 Form 10-K, File No. 1-8222)
10.49 Vermont Transmission and Interconnection Agreement between New England Power Company and Central Vermont Public Service Corporation and Green Mountain Power Corporation with the consent of Vermont Electric Power Company, Inc., dated May 1, 1985. (Exhibit C-128, 1985 Form 10-K, File No. 1-8222)
10.50 Service Contract Agreement between the Company and the State of Vermont for distribution and sale of energy from St. Lawrence power projects ("NYPA Power") dated as of June 25, 1985. (Exhibit C-130, 1985 Form 10-K, File No. 1-8222)
10.50.1 Lease and Operating Agreement between the Company and the State of Vermont dated as of June 25, 1985. (Exhibit C-131, 1985 Form 10-K, File No. 1-8222)
10.51 System Sales & Exchange Agreement Between Niagara Mohawk Power Corporation and Central Vermont Public Service Corporation dated October 1, 1986. (Exhibit C-133, 1986 Form 10-K, File No. 1-8222)
10.54 Transmission Agreement between Vermont Electric Power Company, Inc. and Central Vermont Public Service Corporation dated January 1, 1986. (Exhibit 10-146, 1986 Form 10-K, File No. 1-8222)
10.55 1985 Four-Party Agreement between Vermont Electric Power Company, Central Vermont Public Service Corporation, Green Mountain Power Corporation and Citizens Utilities dated July 1, 1985. (Exhibit 10-147, 1986 Form 10-K, File No. 1-8222)
10.55.1 Amendment dated February 1, 1987. (Exhibit 10-171, 1987 Form 10-K, File No. 1-8222)
10.56 1985 Option Agreement between Vermont Electric Power Company, Central Vermont Public Service Corporation, Green Mountain Power Corporation and Citizens Utilities dated December 27, 1985. (Exhibit 10-148, 1986 Form 10-K, File No. 1-8222)
10.56.1 Amendment No. 1 dated September 28, 1988. (Exhibit 10-182, 1988 Form 10-K, File No. 1-8222)
10.56.2 Amendment No. 2 dated October 1, 1991. (Exhibit 10.56.2, 1991 Form 10-K, File No. 1-8222)
* 10.56.3 Amendment No. 3 dated December 31, 1994
10.57 Highgate Transmission Agreement dated August 1, 1984 by and between the owners of the project and the Vermont electric distribution companies. (Exhibit 10-156, 1986 Form 10-K, File No. 1-8222)
10.57.1 Amendment No. 1 dated September 22, 1985. (Exhibit 10-157, 1986 Form 10-K, File No. 1-8222)
10.58 Vermont Support Agency Agreement re: Quebec Interconnection - Phase II between Vermont Electric Power Company, Inc. and participating Vermont electric utilities dated June 1, 1985. (Exhibit 10-158, 1986 Form 10K, File No. 1-8222)
10.58.1 Amendment No. 1 dated June 20, 1986. (Exhibit 10-159, 1986 Form 10-K, File No. 1-8222)
10.59 Indemnity Agreement B-39 dated May 9, 1969 with amendments 1-16 dated April 17, 1970 thru April 16, 1985 between licensees of Millstone Unit No. 3 and the Nuclear Regulatory Commission. (Exhibit 10-161, 1986 Form 10-K, File No. 1-8222)
10.59.1 Amendment No. 17 dated November 25, 1985. (Exhibit 10-162, 1986 Form 10-K, File No. 1-8222)
10.62 Contract for the Sale of 50MW of firm power between Hydro-Quebec and Vermont Joint Owners of Highgate Facilities dated February 23, 1987. (Exhibit 10-173, 1987 Form 10-K, File No. 1-8222)
10.63 Interconnection Agreement between Hydro-Quebec and Vermont Joint Owners of Highgate facilities dated February 23, 1987. (Exhibit 10-174, 1987 Form 10-K, File No. 1-8222)
10.63.1 Amendment dated September 1, 1993 (Exhibit 10.63.1, 1993 Form 10-K, File No. 1-8222)
10.64 Firm Power and Energy Contract by and between Hydro-Quebec and Vermont Joint Owners of Highgate for 500MW dated December 4, 1987. (Exhibit 10-175, 1987 Form 10-K, File No. 1-8222)
10.64.1 Amendment No. 1 dated August 31, 1988. (Exhibit 10-191, 1988 Form 10-K, File No. 1-8222)
10.64.2 Amendment No. 2 dated September 19, 1990. (Exhibit 10-202, 1990 Form 10-K, File No. 1-8222)
10.64.3 Firm Power & Energy Contract dated January 21, 1993 by and between Hydro-Quebec and Central Vermont Public Service Corporation for the sale back of 25 MW of power. (Exhibit 10.64.3, 1992 Form 10-K, File No. 1-8222)
10.64.4 Firm Power & Energy Contract dated January 21, 1993 by and between Hydro-Quebec and Central Vermont Public Service Corporation for the sale back of 50 MW of power. (Exhibit 10.64.4, 1992 Form 10-K, File No. 1-8222)
10.66 Hydro-Quebec Participation Agreement dated April 1, 1988 for 600 MW between Hydro-Quebec and Vermont Joint Owners of Highgate. (Exhibit 10-177, 1988 Form 10-K, File No. 1-8222)
10.67 Sale of firm power and energy (54MW) between Hydro-Quebec and Vermont Utilities dated December 29, 1988. (Exhibit 10-183, 1988 Form 10-K, File No. 1-8222)
10.75 Receivables Purchase Agreement between Central Vermont Public Service Corporation, Central Vermont Public Service Corporation as Service Agent and The First National Bank of Boston dated November 29, 1988. (Exhibit 10-192, 1988 Form 10-K)
10.75.1 Agreement Amendment No. 1 dated December 21, 1988 (Exhibit 10.75.1, 1993 Form 10-K, File No. 1-8222)
10.75.2 Letter Agreement dated December 4, 1989 (Exhibit 10.75.2, 1993 Form 10-K, File No. 1-8222)
10.75.3 Agreement Amendment No. 2 dated November 29, 1990 (Exhibit 10.75.3, 1993 Form 10-K, File No. 1-8222)
10.75.4 Agreement Amendment No. 3 dated November 29, 1991 (Exhibit 10.75.4, 1993 Form 10-K, File No. 1-8222)
10.75.5 Agreement Amendment No. 4 dated November 29, 1992 (Exhibit 10.75.5, 1993 Form 10-K, File No. 1-8222)
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
A 10.68 Stock Option Plan for Non-Employee Directors dated July 18, 1988. (Exhibit 10-184, 1988 Form 10-K, File No. 1-8222)
A 10.69 Stock Option Plan for Key Employees dated July 18, 1988. (Exhibit 10-185, 1988 Form 10-K, File No. 1-8222)
A 10.70 Officers Supplemental Insurance Plan authorized July 9, 1984. (Exhibit 10-186, 1988 Form 10-K, File No. 1-8222)
A 10.71 Officers Supplemental Deferred Compensation Plan dated November 4, 1985. (Exhibit 10-187, 1988 Form 10-K, File No. 1-8222)
A 10.72 Directors' Supplemental Deferred Compensation Plan dated November 4, 1985. (Exhibit 10-188, 1988 Form 10-K, File No. 1-8222)
A 10.73 Management Incentive Compensation Plan as adopted September 9, 1985. (Exhibit 10-189, 1988 Form 10-K, File No. 1-8222)
A 10.73.1 Revised Management Incentive Plan as adopted February 5, 1990. (Exhibit 10-200, 1989 Form 10-K, File No. 1-8222)
A 10.74 Officers' Change of Control Agreements as approved October 3, 1988. (Exhibit 10-190, 1988 Form 10-K, File No. 1-8222)
A 10.78 Stock Option Plan for Non-Employee Directors dated April 30, 1993 (Exhibit 10.78, 1993 Form 10-K, File No. 1-8222)
A 10.79 Officers Insurance Plan dated November 15, 1993 (Exhibit 10.79, 1993 Form 10-K, File No. 1-8222)
A 10.80 Directors'Supplemental Deferred Compensation Plan dated (Exhibit 10.80, 1993 Form 10-K, File No. 1-8222)
A 10.81 Officers' Supplemental Deferred Compensation Plan dated (Exhibit 10.81, 1993 Form 10-K, File No. 1-8222)
A - Compensation related plan, contract, or arrangement.
16. Change in certifying accountant (July 1, 1985 Form 8-K, File No. 1-8222)
18. Letter re change in accounting principles (1980 3rd Quarter Form 10-Q, File No. 1-8222)
21. Subsidiaries of the Registrant
* 21.1 List of Subsidiaries of Registrant
23. Consents of Experts and Counsel
* 23.1 Consent of Independent Public Accountants
27. Financial Data Schedule
(b) Reports on Form 8-K:
The Company filed the following reports on Form 8-K during the quarter ended December 31, 1994:
1. Item 5. Other Events, dated October 31, 1994 re: Retail Rate Order.
2. Item 5. Other Events, dated November 9, 1994 re: Third quarter 1994 report to shareholders and a press release reporting a new corporate strategy.
Item 7. Financial Statements, Pro Forma Financial Information and Exhibits. Exhibit Number 13, Letter to Shareholders. Exhibit Number 20, Press Release.
3. Item 5. Other Events, dated December 30, 1994 re: Legal proceeding.
Report of Independent Public Accountants To the Board of Directors of Central Vermont Public Service Corporation:
We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements included in Central Vermont Public Service Corporation's annual report to shareholders, included in this Form 10-K, and have issued our report thereon dated February 6, 1995. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed in the index above is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly state, in all material respects, the consolidated financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Boston, Massachusetts February 6, 1995
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
By /s/ Thomas C. Webb -------------------------------------- Thomas C. Webb, President and Chief Executive Officer
By /s/ Robert H. Young -------------------------------------- Robert H. Young, Executive Vice President - Chief Operating Officer
By /s/ Frederick S. Potter -------------------------------------- Frederick S. Potter, Vice President - Finance and Administration and Principal Financial Officer
By /s/ James M. Pennington -------------------------------------- James M. Pennington, Controller and Principal Accounting Officer
March 13, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
March 13, 1995 /s/ Frederic H. Bertrand ----------------------------------------- Frederic H. Bertrand Director
March 13, 1995 /s/ Robert P. Bliss, Jr. ----------------------------------------- Robert P. Bliss, Jr. Director
March 13, 1995 /s/ Elizabeth Coleman ----------------------------------------- Elizabeth Coleman Director
March 13, 1995 /s/ ----------------------------------------- Luther F. Hackett Director
March 13, 1995 /s/ F. Ray Keyser, Jr. ----------------------------------------- F. Ray Keyser, Jr. Director
March 13, 1995 /s/ Mary Alice McKenzie ----------------------------------------- Mary Alice McKenzie Director
March 13, 1995 /s/ Gordon P. Mills ----------------------------------------- Gordon P. Mills Director
March 13, 1995 /s/ Preston Leete Smith ----------------------------------------- Preston Leete Smith Director
March 13, 1995 /s/ Robert D. Stout ----------------------------------------- Robert D. Stout Director
March 13, 1995 /s/ Thomas C. Webb ----------------------------------------- Thomas C. Webb Director


Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Earnings Overview.
The Company's earnings per share of common stock declined by 34% in 1994 to $1.08 from $1.64 per share in 1993. The return on common equity was 7.2% for 1994 and 11.0% for 1993. Earnings per share of common stock and return on common equity for 1992 were $1.71 and 11.8%, respectively. In 1992, earnings and earnings per share of common stock were reduced by approximately $3.0 million and $.27, respectively, for an anticipated environmental cleanup. Weak sales, increased cost of operations and fourth quarter charges, discussed below and described in results of operations, are primarily responsible for reduced earnings for 1994.
During the fourth quarter of 1994, the Company incurred three non- recurring charges. The first resulted from cost disallowances associated with the Vermont Public Service Board (PSB) Rate Order described below, which reduced after tax earnings and earnings per share of common stock by approximately $1.8 million and $.16, respectively. The second resulted from the Company's decision to discontinue its proposed new headquarters office building which reduced after tax earnings and earnings per share of common stock by $1.7 million and $.14, respectively. The third resulted from writing down SmartEnergy Service Inc.'s investment in Green Technologies, Inc.'s common stock to reflect management's estimate of the decline in value of the investment. As a result, after-tax earnings and earnings per share of common stock were reduced by $.8 million and $.07, respectively.
Absent the non-recurring charges, net income and earnings per share of common stock would have been as follows (dollars in thousands):
Year Ended December 31 1994 1993 1992
Net income as reported $14,800 $21,292 $21,422 Non-recurring charges, net of taxes 4,336 - 2,965 ------- ------- ------- Net income before non-recurring charges $19,136 $21,292 $24,387 ======= ======= =======
Earnings per share of common stock before non-recurring charges $1.45 $1.64 $1.98
As a result of these non-recurring charges, the Company earned an 8.4% return on its Vermont utility business and a 1.1% return on non-utility investments. The combined non-utility investments return of 1.1% resulted from a 4.9% return from Catamount Energy Corporation and a 34.2% loss from SmartEnergy Services, Inc. primarily caused by the write down of its investment in Green Technologies, Inc. See Item 8


Item 8. Financial Statements and Supplementary Data.
Index to Financial Statements and Supplementary Data Page No. Report of Independent Public Accountants............................. 30
Financial Statements:
Consolidated Statement of Income for each of the three years ended December 31, 1994............................... 31
Consolidated Statement of Cash Flows for each of the three years ended December 31, 1994........................... 32
Consolidated Balance Sheet at December 31, 1994 and 1993.......................................................... 33
Consolidated Statement of Capitalization at December 31, 1994 and 1993........................................ 35
Consolidated Statement of Changes in Common Stock Equity for each of the three years ended December 31, 1994................................................. 36
Notes to Consolidated Financial Statements......................... 37
Report of Independent Public Accountants To the Board of Directors of Central Vermont Public Service Corporation:
We have audited the accompanying consolidated balance sheet and statement of capitalization of Central Vermont Public Service Corporation and its wholly owned subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of income, changes in common stock equity and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Central Vermont Public Service Corporation and its wholly owned subsidiaries as of December 31, 1994 and 1993 and the results of their operations and cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Boston, Massachusetts February 6, 1995
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 Summary of significant accounting policies
Consolidation The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries.
Regulation The Company is subject to regulation by the Vermont Public Service Board (PSB), the Federal Energy Regulatory Commission (FERC) and, to a lesser extent, the public utilities commissions in other New England states where the Company does business, with respect to rates charged for service, accounting and other matters pertaining to regulated operations. As such, the Company currently prepares its financial statements in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation, and records various regulatory assets and liabilities. In order for a company to report under SFAS No. 71, the Company's rates must be designed to recover its costs of providing service, and the Company must be able to collect those rates from customers. If rate recovery of these costs becomes unlikely or uncertain, whether due to competition or regulatory action, these accounting standards may no longer apply to the Company's regulated operations. Management believes that the Company currently meets the criteria for continued application of SFAS No. 71, but will continue to evaluate significant changes in the regulatory and competitive environment to assess the Company's overall consistency with the criteria of SFAS No. 71. In the event the Company determines that it no longer meets the criteria for applying SFAS No. 71, the accounting impact would be an extraordinary non-cash charge to operations of an amount that could be material.
Revenues Estimated unbilled revenues are recorded at the end of accounting periods. Unbilled revenues of approximately $18.6 million, $18.3 million and $18.5 million for 1992, 1993 and 1994, respectively, are included in revenues on the Consolidated Statement of Income.
Maintenance Maintenance and repairs, including replacements not qualifying as retirement units of property, are charged to maintenance expense. Replacements of retirement units are charged to utility plant. The original cost of units retired plus the cost of removal, less salvage, is charged to the accumulated provision for depreciation.
Depreciation The Company uses the straight-line remaining life method of depreciation. Total depreciation expense was approximately 3.5% of the cost of depreciable utility plant for each of the years 1992 through 1994.
Income Taxes The Company records income taxes in accordance with SFAS No. 109, Accounting for Income Taxes, which requires an asset and liability approach to determine income tax liabilities. The standard recognizes tax assets and liabilities for the cumulative effect of all temporary differences between financial statement carrying amounts and the tax basis of assets and liabilities, see Note 11. The deferred method under Accounting Principle Board's Opinion 11, was applied in 1992. Deferred income taxes were provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. Investment tax credits associated with utility plant are deferred and amortized ratably to income over the lives of the related properties. Investment tax credits associated with non-utility plant are recognized as income in the year realized.
Allowance for Funds During Construction Allowance for funds used during construction (AFDC) is the cost, during the period of construction, of debt and equity funds used to finance construction projects. The Company capitalizes AFDC as a part of the cost of major utility plant projects to the extent that costs applicable to such construction work in progress have not been included in rate base in connection with rate-making proceedings. AFDC equity represents a current non-cash credit to earnings which is recovered over the life of the property. The AFDC rates used by the Company were 10.51%, 5.09% and 8.05% for the years 1992 through 1994, respectively.
Regulatory Assets and Other Deferred Charges Certain costs are deferred and amortized in accordance with authorized or expected rate-making treatment. The major components of these costs are $19.2 million for Conservation and Load Management, $12.4 million for Yankee Atomic Electric Company dismantling costs, $10.6 million for SFAS No. 109, and $4.8 million of restructuring costs. During regular nuclear refueling outages, the increased costs attributable to replacement energy purchased from NEPOOL and maintenance costs are deferred and amortized ratably to expense until the next regularly scheduled refueling shutdown. The Company earns a return on the unamortized replacement energy and maintenance costs. See Note 2 to the Consolidated Financial Statements for discussion of the costs associated with the discontinued operation of the Yankee Atomic Nuclear Power Corporation nuclear power plant.
Purchased Power The Company records the annual cost of power obtained under long-term contracts as operating expenses. Since these contracts, as more fully described in Note 13, do not convey to the Company the right to use property, plant, or equipment, they are considered executory in nature. This accounting treatment is in contrast to the Company's commitment with respect to the Hydro Quebec Phase I and II transmission facilities which are considered capital leases. As such, the Company has recorded a liability for its commitment under the Phase I and II arrangements and recognized an asset for the right to use these facilities.
Note 2 Investments in affiliates
The Company uses the equity method to account for its investments in the following companies (dollars in thousands): December 31 Ownership 1994 1993 Nuclear generating companies: Vermont Yankee Nuclear Power Corporation 31.3% $16,916 $16,811 Connecticut Yankee Atomic Power Company 2.0% 2,011 2,016 Maine Yankee Atomic Power Company 2.0% 1,338 1,349 Yankee Atomic Electric Company 3.5% 813 836 ------- ------- 21,078 21,012 Vermont Electric Power Company, Inc.: Common stock 56.8% 3,494 3,498 Preferred stock 2,193 2,453 ------- ------- $26,765 $26,963 ======= =======
Each sponsor of the nuclear generating companies is obligated to pay an amount equal to its entitlement percentage of fuel, operating expenses (including decommissioning expenses) and cost of capital and is entitled to a similar share of the power output of the plants. The Company's entitlement percentages are identical to the ownership percentages except that Vermont Yankee's entitlement percentage is 35%. The Company is obligated to contribute its entitlement percentage of the capital requirements of Vermont Yankee and Maine Yankee and has a similar, but limited, obligation to Connecticut Yankee. The Company is responsible for paying its entitlement percentage of decommissioning costs for Vermont Yankee, Connecticut Yankee, Maine Yankee and Yankee Atomic as follows (dollars in millions):
CVPS's Total Share of Date of Estimated CVPS's Funded Study Obligation Obligation Obligation Nuclear generating companies: Vermont Yankee 1993 $312.7 $109.4 $40.3 Maine Yankee 1993 $316.6 $6.3 $2.2 Connecticut Yankee 1992 $294.2 $5.9 $3.0 Yankee Atomic 1994 $370 $13.0 $3.6
On February 26, 1992, the Board of Directors of Yankee Atomic decided to permanently discontinue operation of their plant, and to decommission the facility.
The Company relied on Yankee Atomic for less than 1.5% of its system capacity. Presently, purchased power costs billed to the Company by Yankee Atomic, which include a provision for ultimate decommissioning of the unit, are being collected from the Company's customers via existing retail rate tariffs.
On March 18, 1993, the FERC approved a settlement agreement regarding the decommissioning plan, recovery of plant investment and all issues with respect to prudency of the decision to discontinue operation which included $247 million of decommissioning costs in 1992 dollars. Based on a new study developed by Yankee Atomic, decommissioning costs are approximately $370 million in 1994 dollars. The increase results primarily from delays in finding a permanent repository for its spent nuclear fuel. The new study is subject to FERC approval. Yankee Atomic is currently collecting from sponsors decommissioning costs based on $247 million in 1992 dollars and anticipates to begin collecting from sponsors based on $370 million in November 1995. The Company's share of the increase in decommissioning costs is approximately $4.3 million.
The Company's total current share of its cost with respect to Yankee Atomic's decision to discontinue operation is approximately $12.4 million. This amount is reflected in the accompanying balance sheet both as a regulatory asset and deferred power contract obligation (current and non- current).
The Company believes that its proportionate share of Yankee Atomic costs will be recovered through the regulatory process and, therefore, the ultimate resolution of the premature retirement of the plant will not have a material adverse effect on the Company's earnings or financial condition.
Although the estimated costs of decommissioning are subject to change due to changing technologies and regulations, the Company expects that the nuclear generating companies' liability for decommissioning, including any future changes in the liability, will be recovered in their rates over their operating or license lives.
The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $8.9 billion. Beyond that a licensee maintains an indemnity agreement with the Nuclear Regulatory Commission, but subject to Congressional approval. The first $200 million of liability coverage is the maximum provided by private insurance. The Secondary Financial Protection Program is a retrospective insurance plan providing additional coverage up to $8.7 billion per incident by assessing $79.3 million against each of the 110 reactor units that are currently subject to the Program in the United States, limited to a maximum assessment of $10 million per incident per nuclear unit in any one year. The maximum assessment is to be adjusted at least every five years to reflect inflationary changes. The Company's interests in the nuclear power units are such that it could become liable for an aggregate of approximately $4.4 million of such maximum assessment per incident per year.
Summarized financial information for Vermont Yankee Nuclear Power Corporation is as follows (dollars in thousands):
Earnings 1994 1993 1992
Operating revenues $162,757 $180,145 $175,919 Operating income $14,355 $16,441 $16,304 Net income $6,588 $7,794 $7,921
Company's equity in net income $2,067 $2,434 $2,476
December 31 Investment 1994 1993
Current assets $ 41,416 $ 40,136 Non-current assets 470,726 429,634 -------- -------- Total assets 512,142 469,770
Less: Current liabilities 37,287 32,021 Non-current liabilities 420,382 383,585 -------- -------- Net assets $ 54,473 $ 54,164 -------- -------- Company's equity in net assets $ 16,916 $ 16,811
Included in Vermont Yankee's revenues shown above are sales to the Company of $52.9 million, $52.3 million and $53.6 million for 1992 through 1994, respectively. These amounts are reflected as purchased power net of deferrals and amortization in the accompanying Consolidated Statement of Income.
Vermont Electric Power Company, Inc. (Velco) and its wholly owned subsidiary Vermont Electric Transmission Company, Inc. (Vetco) own and operate transmission systems in Vermont over which bulk power is delivered to all electric utilities in the state. Velco has entered into transmission agreements with the state of Vermont and the electric utilities and under these agreements bills all costs, including interest on debt and a fixed return on equity, to the state and others using the system. These contracts enable Velco to finance its facilities primarily through the sale of first mortgage bonds. Included in Velco's revenues shown below are transmission services to the Company (reflected as production and transmission in the accompanying Consolidated Statement of Income) amounting to $8.3 million, $8.9 million and $8.4 million for 1992 through 1994, respectively.
Velco operates pursuant to the terms of the 1985 Four-Party Agreement (as amended) with the Company and two other major distribution companies in Vermont. Although the Company owns 56.8% of Velco's outstanding common stock, the Four-Party Agreement effectively restricts the Company's control of Velco. Therefore, Velco's financial statements have not been consolidated. The Four- Party Agreement continues in full force and effect until May 1995 and will be extended for an additional two-year term in May 1995, and every two years thereafter, unless at least ninety (90) days prior to any two-year anniversary any party shall notify the other parties in writing that it desires to terminate the agreement as of such anniversary. No such notification has been filed by the parties. The Company also owns 46.6% of Velco's outstanding preferred stock, $100 par value.
Summarized financial information for Velco is as follows (dollars in thousands):
Earnings 1994 1993 1992
Transmission revenues $16,761 $17,891 $16,722 Operating income $3,350 $4,423 $4,379 Net income $1,296 $1,375 $1,494
Company's equity in net income $638 $698 $749
December 31 Investment 1994 1993
Current assets $16,549 $15,181 Non-current assets 53,175 55,018 ------- ------- Total assets 69,724 70,199
Less: Current liabilities 15,941 13,180 Non-current liabilities 42,909 45,626 ------- ------- Net assets $10,874 $11,393 ======= ======= Company's equity in net assets $ 5,687 $ 5,951
Note 3 Non-utility investments
The Company's wholly owned subsidiary, Catamount Energy Corporation (Catamount) invests through its wholly owned subsidiaries in non-regulated, energy-related projects. Certain financial information for Catamount's investments is set forth in the table that follows (dollars in thousands):
The Rumford project was placed in service on August 1, 1990. The Ryegate and Williams Lake projects began commercial operation on November 1, 1992 and April 2, 1993, respectively. On October 26, 1992, Appomattox purchased a 50% partnership interest in Appomattox Cogeneration which owns a power sales agreement associated with a cogeneration facility currently in operation.
In January 1994, Catamount purchased an additional 4.185% limited partnership interest in Rumford Cogeneration Co. This additional investment increased Rumford's ownership in the project to 15.1%.
SmartEnergy Services, Inc. (SmartEnergy) also is a wholly owned subsidiary of the Company, whose purpose is to cost effectively provide reliable, energy efficient products and services, including the rental of electric water heaters. Prior to January 1, 1993, the rental electric water heater program was part of the Company's core electric business and reported as non-operating income.
On October 1, 1993, SmartEnergy purchased for $1.2 million, 304,125 shares (5%) of Green Technologies, Inc. (Green Technologies) common stock and on September 19, 1994, purchased for $540,000, an additional 120,000 shares (1.8%). This investment increased SmartEnergy's ownership in Green Technologies to 6.8%. Green Technologies of Boulder, Colorado, currently manufactures Green Plug electricity savers for several types of household appliances. SmartEnergy uses the cost method of accounting for its investment in Green Technologies. During the fourth quarter of 1994, SmartEnergy wrote- down its investment in Green Technologies by approximately $1.3 million to reflect management's estimate of the permanent decline in value of the investment. SmartEnergy's investment in Green Technologies was approximately $.42 million and $1.2 million at December 31, 1994 and 1993, respectively.
Note 4 Redeemable preferred stock
Commencing in 1998, the 8.30% Dividend Series Preferred Stock is redeemable at par through a mandatory sinking fund in the amount of $1.0 million per annum, and at its option, the Company may redeem at par an additional non-cumulative $1.0 million per annum.
Note 5 Common Stock
On November 8, 1994, the Company's board of directors (Board) announced a new dividend policy that targeted future dividends at 60% of earnings. In light of the new policy, the current annual dividend of $1.42 was reduced 44% to $.80 effective with the first quarter dividend paid in February 1995. Accordingly, on December 5, 1994, the Board declared a quarterly common stock dividend of $.20 per share payable February 15, 1995 to shareholders of record on January 31, 1995. The dividend payment level will be reviewed regularly in light of capital needs, projected earnings levels and other relevant factors. Also, the Board authorized the purchase of up to 2 million shares of its outstanding common stock in open market transactions. As of December 31, 1994, the Company had purchased 56,400 shares at an average price of $12.98 per share. These transactions are recorded as treasury stock, at cost, in the Company's Consolidated Balance Sheet.
As of February 8, 1995, the Company had purchased 74,700 shares at an average price of $12.99 per share.
Note 6 Long-term debt and sinking fund requirements
Based on issues outstanding at December 31, 1994, the aggregate amount of long-term debt maturities and sinking fund requirements (exclusive of the amount that may be satisfied by property additions) are approximately $4.2 million, $1.0 million, $3.0 million, $20.5 million and $5.5 million for the years 1995 through 1999, respectively. Substantially all property and plant is subject to liens under the First Mortgage Bonds.
Note 7 Financial instruments
The estimated fair values of the Company's financial instruments at December 31, 1994 are as follows (dollars in thousands):
Carrying Fair Amount Value
Cash and temporary cash investments $ 7,559 $ 7,559 Short-term debt $ 11,511 $ 11,511 Investments $ 424 $ 424 Sale of accounts receivable and unbilled revenues $ 12,000 $ 12,000 Redeemable preferred stock $ 20,000 $ 18,790 Long-term debt $124,387 $119,374
The carrying amount for cash, temporary cash investments and short-term debt approximates fair value because of the short maturity of those instruments.
The carrying amount and the fair value of the Company's investment in Green Technologies, Inc. reflects management's estimate of the realizable value of the investment.
The carrying amount for the sale of accounts receivable and unbilled revenues approximates fair value because of the short maturity of those instruments.
The fair value of the Company's redeemable preferred stock and long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same remaining maturation.
Anticipated regulatory treatment of any excess or decline in the fair value relative to the carrying value of the Company's financial instruments, if they were settled at amounts approximating those above, would result in an increase or decrease in the Company's rates over a prescribed amortization period. Accordingly, any settlement would not result in a material impact on the Company's financial position or results of operations.
The Company has no financial instruments that fall under the guidance of SFAS No. 119, Disclosure about Derivative Financial Instruments and Fair Value of Financial Instruments.
In May 1993, the FASB issued SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, effective for fiscal years beginning after December 15, 1993. SFAS No. 115 addresses the accounting and reporting for investments in equity securities that have readily determinable fair values and for all investments in debt securities. The Company has the following investments that are covered by the principles of SFAS No. 115: temporary cash investments classified as trading activities and reported at market value, and its available for sale investment in Green Technologies, Inc. For additional information, see Note 3 herein. The adoption of SFAS No. 115 had no material impact on the Company's financial position or results of operations.
Note 8 Accounts receivable
In 1988 the Company entered into an agreement to sell up to $20 million of certain accounts receivable and unbilled revenues. At December 31, 1994 and 1993, a total of $12 million of accounts receivable and unbilled revenues were sold under an accounts receivable facility.
Accounts receivable and unbilled revenues that have been sold were transferred with limited recourse. A pool of assets, varying between 3% to 5% of the accounts receivable and unbilled revenues sold, are set aside for this potential recourse liability. Accounts receivable and unbilled revenues are reflected net of sales of $4.2 million and $7.8 million, respectively, at December 31, 1994 and $4.7 million and $7.3 million, respectively, at December 31, 1993.
Accounts receivable are also reflected net of an allowance for uncollectible accounts of $1.0 million and $.9 million at December 31, 1994 and 1993, respectively.
Note 9 Short-term debt
Utility
The Company uses committed lines of credit and uncommitted loan facilities to finance its construction and C&LM programs, on a short-term basis, and for other corporate purposes. As of December 31, 1994, the Company had $18.25 million of committed lines of credit and $25 million of uncommitted loan facilities which are normally renewed upon expiration and require annual fees ranging from zero to .25% of an individual line. Borrowings under these short-term debt arrangements are at interest rates ranging from less than prime to the prime rate. The Company had $11.5 million and $1.4 million of outstanding short-term debt at December 31, 1994 and 1993, respectively, at average interest rates of 5.22% for 1994 and 3.61% for 1993.
Non-Utility
Catamount maintains an Irrevocable Standby Letter of Credit with a bank to borrow up to an aggregate amount of $2.3 million to replace its share of cash in the Appomattox Cogeneration Limited Partnership's Project Debt Service Reserve Fund. This Letter of Credit is for a one-year term with annual extensions available and requires fees totaling 2.527% of credit available. At December 31, 1994 and 1993, there were no borrowings outstanding under this Letter of Credit. Catamount believes it will not have to perform under this agreement because the likelihood of default by the primary party is remote.
SmartEnergy maintains a $1.0 million revolving line of credit with a bank to provide working capital and financing assistance for investment purposes. SmartEnergy had $846,000 and $696,000 of outstanding short-term debt at December 31, 1994 and 1993, respectively, at average interest rates of 7.29% for 1994 and 6.08% for 1993.
Financial obligations of the non-utility wholly owned subsidiaries are non-recourse to the Company.
Note 10 Pension and postretirement benefits
The Company has a non-contributory trusteed pension plan covering all employees (union and non-union). Under the terms of the pension plan, employees are generally eligible for monthly benefit payments upon reaching the age of 65 with a minimum of five years of service. The Company's funding policy is to contribute, at least, the statutory minimum to a trust. The Company is not required by its union contract to contribute to multi-employer plans.
The projected unit credit actuarial cost method was used to compute net pension costs and the accumulated and projected benefit obligations. The change in the accumulated benefit obligation and projected benefit obligation for 1993 and 1994 results primarily from changes in plan assumptions. The following table sets forth the funded status of the pension plan and amounts recognized in the Company's Balance Sheet and Statement of Income (dollars in thousands): December 31 1994 1993 1992 Funded status of the plan Vested benefit obligation $35,869 $35,837 $27,899 Non-vested benefit obligation 312 493 439 ------- ------- ------- Accumulated benefit obligation $36,181 $36,330 $28,338 ------- ------- -------
Projected benefit obligation $46,669 $49,743 $39,001 Market value of plan assets (primarily equity and fixed income securities) 44,115 46,074 39,768 ------- ------- ------- Projected benefit obligation more (less) than market value of plan assets 2,554 3,669 (767) Unrecognized net transition assets 1,608 1,768 1,929 Unrecognized prior service costs (3,178) (3,568) (3,084) Unrecognized net gain 5,963 1,498 5,314 ------- ------- ------- Net pension liability 6,947 3,367 3,392 Less regulatory asset for restructuring costs 1,974 - - ------- ------- ------- Effective accrued pension costs $ 4,973 $ 3,367 $ 3,392 ------- ------- -------
Net pension costs include the following components Service cost $ 2,065 $ 1,491 $ 1,307 Interest cost 3,694 3,377 3,065 Actual return on plan assets 515 (6,800) (4,137) Net amortization and deferral (4,095) 3,391 890 ------- ------- ------- Pension costs 2,179 1,459 1,125 Amortization of regulatory asset 261 - - ------- ------- ------- Effective pension costs 2,440 1,459 1,125 Less amount allocated to other accounts 318 276 223 ------- ------- ------- Net pension costs expensed $ 2,122 $ 1,183 $ 902 ------- ------- -------
Assumptions used in calculating pension cost were as follows:
December 31 1994 1993 1992
Weighted average discount rates 8.50% 7.25% 8.50% Expected long-term return on assets 9.50% 9.75% 10.25% Rate of increase in future compensation levels 5.00% 4.75% 5.50%
The Company sponsors a defined benefit postretirement medical plan that covers all employees who retire with ten years or more of service after age 45.
Effective January 1, 1993, the Company adopted, on a prospective basis, SFAS No. 106, Employer's Accounting for Postretirement Benefits Other Than Pensions (OPEB) which requires accrual of the expected costs of such benefits during the employees' years of service. In 1994, the Company adopted a policy to fund its OPEB obligation through a Voluntary Employees' Benefit Association and 401(h) Subaccount in its Pension Plan.
The following table sets forth the plan's funded status and amounts recognized in the Company's Balance Sheet and the amount of expense charged to the Company's Statement of Income in accordance with SFAS No. 106 (dollars in thousands): December 31 1994 1993 Accumulated postretirement benefit obligation Retirees $(8,265) $(5,098) Fully eligible active plan participants (521) (1,207) Other active plan participants (806) (1,293) Plan assets at fair value 744 - ------- ------- Accumulated postretirement benefit obligation in excess of plan assets (8,848) (7,598) Unrecognized transition obligation 5,485 6,253 Unrecognized net loss 337 351 ------- ------- Accrued postretirement benefit cost (3,026) (994) Regulatory asset for restructuring costs 2,008 - ------- ------- Effective accrued postretirement benefit costs $(1,018) $ (994) ======= ======= Net postretirement benefit cost includes the following components Service cost $ 194 $ 168 Interest cost 682 588 Actual return on plan assets 1 - Deferral of asset gain during the year (1) - Amortization of transition obligation over a twenty-year period 305 329 ------- ------- Postretirement benefit cost 1,181 1,085 Amortization of regulatory asset 265 - ------- ------- Effective postretirement benefit cost 1,446 1,085 Less amount allocated to other accounts 172 205 ------- ------- Net postretirement benefit cost expensed $ 1,274 $ 880 ======= =======
Assumptions used in the per capita costs of the accumulated postretire- ment benefit obligation were as follows:
December 31 1994 1993 Per capita percent increase in health care costs: Pre-65 9.50% 9.50% Post-65 8.00% 6.00% Weighted average discount rates 8.50% 7.25% Rate of increase in future compensation levels 5.00% 4.75%
Health care trend rates are assumed to decrease to 6.0% for pre-65 and 5.5% for post-65 for the year 2001 and thereafter.
This decrease results from changes to the retiree medical plan limiting the cost for employees retiring after 1995 to the 1995 per participant cost. Increasing the assumed health care cost trend rates by one percentage point in each year would have resulted in an increase of approximately $709,000 in the accumulated postretirement benefit obligation as of January 1, 1995, and an increase of about $57,000 in the aggregate of the service cost and interest cost components of net periodic postretirement benefit cost for 1994. Prior to 1993, the Company expensed OPEB's costs as benefits were paid. Such costs totaled $546,000 for 1992.
Effective January 1, 1994, the Company adopted, on a prospective basis, SFAS No. 112, Employers' Accounting for Postemployment Benefits which requires accrual of the expected cost of postemployment benefits provided to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement. The Company provides postemployment benefits consisting of long-term disability benefits, and prior to January 1, 1994 expensed these costs as benefits were paid. Such costs total $91,000 and $156,000 for 1992 and 1993, respectively. The accumulated postemployment benefit obligation at January 1, 1995 of approximately $1.3 million is reflected in the accompanying balance sheet as a deferred postemployment benefit obligation (current and non-current) and is offset by a corresponding regulatory asset of approximately $1.0 million. The PSB in its October 31, 1994 Rate Order allowed the Company to recover the regulatory asset over a 7-1/2 year period beginning November 1, 1994 through April 30, 2002. The postemployment benefit cost charged to expense in 1994 was approximately $324,000 (pre-tax).
In the first quarter of 1994, the Company offered and recorded an obligation related to a Voluntary Retirement Program (VRP). The VRP was accepted by 42 employees. The estimated benefit obligation for the VRP as of December 31, 1994 is about $4.5 million. This amount consists of pension benefits and postretirement medical benefits of $2.2 million and $2.3 million, respectively. Additionally, 32 employees accepted a Voluntary Severance Program (VSP) offered by the Company. Eligible employees had until April 22, 1994 to apply. The Company also announced a layoff of 20 employees on May 9, 1994. VSP and layoff obligations of $.8 million and $.2 million, respectively, were recorded in the second quarter of 1994. At December 31, 1994, the benefit obligation for the VSP was about $96,000. The VRP, VSP and layoff combined with attrition since mid-1993, yields a total work force reduction of approximately 14%. In the October 31, 1994 PSB Rate Order, the Company was allowed rate recovery of this restructuring cost over a five-year period. The unamortized balance of these costs was approximately $4.8 million at December 31, 1994.
Note 11 Income taxes
The components of Federal and state income tax expense are as follows (dollars in thousands):
Year Ended December 31 1994 1993 1992 Federal: Current $ 6,177 $ 2,751 $ 7,774 Deferred 3,417 7,893 2,042 Investment tax credits, net (391) (391) (391) ------- ------- ------- 9,203 10,253 9,425 ------- ------- ------- State: Current 1,710 406 1,987 Deferred 496 2,113 1,001 ------- ------- ------- 2,206 2,519 2,988 ------- ------- ------- Total Federal and state income taxes $11,409 $12,772 $12,413 ======= ======= =======
Federal and state income taxes charged (credited) to: Operating expenses $11,934 $12,496 $12,102 Other income (525) 276 311 ------- ------- ------- $11,409 $12,772 $12,413 ======= ======= =======
The principal components of deferred income tax expense for 1992 were additional depreciation for tax purposes of $3.9 million offset by $.9 million of contributions in aid of construction.
The principal items comprising the difference between the total income tax expense and the amount calculated by applying the statutory Federal income tax rate to income before tax are as follows (dollars in thousands):
Year Ended December 31 1994 1993 1992
Income before income tax $26,209 $34,064 $33,835 Federal statutory rate 35% 35% 34% Federal statutory tax expense $ 9,173 $11,922 $11,504 Increases (reductions) in taxes resulting from: Disallowed regulatory tax asset 1,641 - - Dividend received deduction (854) (995) (353) Deferred taxes on plant previously "flowed-through" 523 523 523 State income taxes net of Federal tax benefit 1,434 1,637 1,707 Investment credit amortization (391) (391) (391) Seabrook project 76 139 70 Book-to-return adjustments and other (193) (63) (647) ------- ------- ------- Total income tax expense provided $11,409 $12,772 $12,413 ======= ======= =======
The tax effects of temporary differences and tax carry forward that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below (dollars in thousands):
Year Ended December 31 1994 1993 Deferred tax assets Alternative minimum tax credit carry forward $ 900 $ 1,400 Non-deductible accruals and othe 4,682 4,186 Deferred compensation and pension 4,651 4,058 Environmental costs accrual 2,335 2,142 ------- ------- Total deferred tax assets 12,568 11,786 ------- ------- Deferred tax liabilities Property, plant and equipment 41,609 38,304 Net regulatory asset 12,217 13,806 Conservation and load management expenditures 7,664 5,123 Nuclear refueling costs 473 2,633 Other 3,315 3,948 ------- ------- Total deferred tax liabilities 65,278 63,814 ------- ------- Net deferred tax liability $52,710 $52,028 ======= =======
As a result of adopting SFAS No. 109 in 1993, the Company recognized additional net accumulated deferred income tax liabilities of approximately $15 million and a net corresponding regulatory asset from customers of approximately $15 million for future revenues that will be received when the temporary differences reverse and are settled in rates. As a result of the October 31, 1994 PSB Rate Order, during the fourth quarter of 1994, the Company recognized an additional $1.6 million of tax expense related primarily to a previous revenue agent review which were expected to be collected from customers through rates.
A valuation allowance has not been recorded, as the Company expects all deferred income tax assets will be utilized in the future.
The Company has an alternative minimum tax credit carry forward of $.9 million which is available to reduce future regular income taxes over an indefinite period.
Note 12 Retail Rate Increase
A PSB Rate Order dated October 31, 1994, allowed the Company a base retail rate increase of 4.27% or approximately $8.6 million effective with service rendered November 1, 1994. On December 14, 1994, the Company received an amended PSB Rate Order which allowed the Company a base retail rate increase of 5.07% or approximately $10.2 million. The Company had filed for an 8.9% or $17.9 million increase in its base retail rates in February 1994. The PSB Rate Order also lowered the allowed rate of return on the Company's common stock equity from 12% to 10%. The allowed return on equity is after deducting a .75% penalty based on the PSB's conclusions that there had been "mismanagement of power supply options" and because of "the Company's failed efforts to acquire all cost-effective energy efficiency resources." The Company disagrees with the PSB's conclusion.
As discussed in Note 11, the Company recorded an additional income tax provision of $1.6 million which it had previously expected to recover in rates but was disallowed in the Rate Order.
Note 13 Commitments and contingencies
The Company's power supply is acquired from a variety of sources including its own generating units, jointly owned units, long-term contracts and short-term purchases from a variety of sources. Through its investments in four nuclear generating companies, the Company is entitled to receive power from those nuclear units. See Note 2 for a discussion of the Company's obligations related to its investment in nuclear generating companies.
Under long-term contracts with various electric utilities in the region, the Company is purchasing certain percentages of the electrical output of production plants constructed and financed by those utilities. Such contracts obligate the Company to pay certain minimum annual amounts representing the Company's proportionate share of fixed costs, including debt service requirements (amounts necessary to retire the principal of and to pay the interest on the portion of the related long-term debt ascribed to the Company) whether or not the production plants are operating. The cost of power obtained under such long-term contracts, including payments required to be made when a production plant is not operating, is reflected as "Purchased power" in the Consolidated Statement of Income.
The Company purchases power from a coal-fired generating plant owned by Northeast Utilities (NU) under a thirty-year contract which expires April 30, 1998. Under this contract the Company is obligated to make capacity payments which amounted to approximately $3.7 million, $3.8 million and $4.3 million for 1992 through 1994, respectively. These capacity payments will vary over the contract period due to factors such as changes in NU's net investment and allowed rate of return.
The Company purchases power from several small power producers who own qualifying facilities under the Public Utility Regulatory Policies Act of 1978. These qualifying facilities produce energy using hydroelectric, wood, biomass, and refuse-burning generation. Under these long-term contracts, in 1994, the Company purchased 34.4 MW of which approximately 30.1 MW is associated with the Vermont Power Exchange and 3.9 MW with a New Hampshire/Vermont solid waste plant owned by Wheelabrator Claremont Company, L.P. The Company expects to purchase approximately 42 MW in each year 1995 through 1999. The total commitment in the next five years to purchase power from these qualifying facilities is approximately $105.9 million.
The Company will receive varying amounts of capacity and energy from two Hydro-Quebec contracts during the period 1995-2016. The contract between a group of Vermont utilities (Vermont Joint Owners) and Hydro-Quebec provides power over the entire period while a contract between the state of Vermont and Hydro-Quebec terminates on September 22, 1995. Additional contracts were negotiated between the Company and Hydro-Quebec which in effect reduce the amount of power the Company is required to purchase, as well as one signed in 1994 which reduces the cost to the Company.
The maximum net amount of capacity that the Company will purchase during the term of the agreements is 142.7 MW. The total commitment in the next five years to purchase power under these contracts is approximately $321 million, less approximately $112 million of power sellbacks, yielding a net cost of approximately $209 million.
Early in the Vermont Joint Owners contract, two sellback contracts were negotiated which reduced the net purchase of Hydro-Quebec power as well as delayed the purchase of about 24 MW of capacity and associated energy. In 1994, the Company negotiated a third sellback arrangement whereby the Company receives an effective discount on up to 70 MW of capacity in the 1996 contract year (declining to 30 MW in the 1999 contract year) in exchange for the right of Hydro-Quebec to reduce capacity deliveries by up to 50 MW beginning as early as 2004 until 2015, and the ability to reduce the amounts of energy delivered in up to five years beginning in 2000.
Joint-ownership The Company's ownership interests in jointly owned generating and transmission facilities are set forth in the table that follows and recorded in the Company's Consolidated Balance Sheet (dollars in thousands):
MW December 31 Ownership Entitlement 1994 1993 Generating plants: Wyman #4 1.78% 11 $ 3,338 $ 3,322 Joseph C. McNeil 20.00% 11 14,871 14,821 Millstone #3 1.73% 20 75,101 75,071 Highgate transmission facility 46.08% 12,775 12,586 -------- -------- 106,085 105,800 Accumulated depreciation 25,683 22,535 -------- -------- $ 80,402 $ 83,265 ======== ========
Wyman #4, an oil-fired generating plant, commenced commercial operation in December 1978. The Joseph C. McNeil wood, gas and oil-fired generating plant commenced commercial operation in June 1984 and the Millstone #3, a nuclear generating unit, commenced commercial operation in April 1986. The Highgate transmission interconnection with Canada was placed in service in September 1985. The Company's share of operating expenses for these facilities is included in the corresponding operating accounts on the Consolidated Statement of Income. Each participant in these facilities must provide for its own financing.
The Company is responsible for paying its ownership percentage of decommissioning costs for Millstone #3. Based on a 1992 study, total estimated obligation at December 31, 1994 was approximately $449 million and the funded obligation was about $76 million. The Company's share for the total obligation and funded obligation was approximately $7.8 million and $1.1 million, respectively.
Environmental The Company is engaged in various operations and activities which subject it to inspection and supervision by both state and Federal regulatory authorities including the United States Environmental Protection Agency (EPA) (hereinafter "environmental laws"). It is Company policy to comply with these environmental laws to the extent currently applicable and effective against it. The Company has implemented various procedures and internal controls to assess and assure compliance. If non-compliance is discovered, corrective action is taken. Based on these efforts and the oversight of those regulatory agencies having jurisdiction, the Company believes it conforms, in all material respects, with these environmental laws.
Company operations occasionally result in unavoidable and inadvertent spills or releases of regulated substances or materials, such as the rupture of a pole mounted transformer, broken hydraulic line, or other similar occurrences. When the Company learns of such spills and releases from ongoing operations, they are cleaned up to meet Federal and state requirements. Except as discussed in the following paragraphs, the Company is not aware of any instances where it has caused, permitted or suffered a release or spill on or about its properties or otherwise which will likely result in any material environmental liabilities to the Company.
The Company is an amalgamation of more than 100 predecessor companies engaged in various operations and activities prior to their being incorporated in the Company. At least two of these companies were involved in the production of gas from coal to sell and distribute to retail customers at three different locations. These activities were discontinued by the Company in the late 1940's or early 1950's. In addition, these predecessor companies and the Company itself may have historically engaged in other waste disposal activities, while legal and consistent with commercially accepted practices at the time, may not meet modern standards and thus represent potential liability. The Company continues to discover, investigate, evaluate, monitor and, where appropriate, remediate contaminated sites related to these historic activities. The Company's policy is to accrue a liability for those sites where costs for remediation, monitoring and other future activities are probable and can be reasonably estimated.
Based on these investigations and policies, coal tar deposits were discovered at the Company's Cleveland Avenue property located in the city of Rutland, a site where one of its predecessors operated a coal-gasification facility. Due to the presence of these deposits and uncertainties as to potential contamination migration off-site, the Company conducted studies to determine the magnitude and extent of the coal tar releases. The Company engaged a consultant to assist in evaluating clean-up methodologies and provide cost estimates. Those studies indicated the cost to remediate the site would be approximately $5 million. This was charged to expense in the fourth quarter of 1992. This was followed by an assessment of potential health, safety and ecological risks. Other site issues are still under evaluation. A final risk assessment report was completed and submitted to the state for review. Following state review, various remediation alternatives will be investigated. The Company was formally contacted by the EPA in January 1995 asking for written consent to conduct a site evaluation. The Company does not believe EPA's evaluation changes its potential liability so long as reasonable further progress is made in remediating the site. The Company has yet to determine whether insurance proceeds are available to offset the cost of any remediation required at this site.
The Company is currently investigating its potential liability regarding three former municipal landfills: the Bennington Landfill, the Parker Landfill, and the Trafton-Hoisington Landfill. The Bennington Landfill is a superfund site located in Bennington, Vermont. The Company was contacted in the winter of 1994 by counsel for a group of potentially responsible parties (PRP Group) who were performing an engineering evaluation and cost analysis (EE/CA) for the site under a settlement agreement with the EPA. The PRP Group threatened contribution litigation against the Company and others to recover an equitable share of the approximate $3 million the PRP Group had expended thus far on the EE/CA. Investigation by the Company thus far suggests that it is unlikely that it contributed a meaningful amount of hazardous substances, if any, to the site and thus would not be liable for a significant share of liability for the EE/CA expenses or site clean up. No litigation by the PRP Group has yet been initiated against the Company.
In July 1994, the EPA notified the Company that it had reviewed evidence which, in its opinion, indicated that the Company may have contributed to the environmental contamination at the site but that a full determination of its potential liability for the site had not been made. EPA, at that time, designated the Company a potentially interested party (PIP). Also in July 1994, the EPA notified the PRP Group, the Company and other PIPs that it was proposing a response action at the site with an estimated total present worth cost of approximately $9.5 million.
During November 1994, the Company was notified that EPA had information indicating that the Company was a PRP. The EPA letter also requested that the Company participate with other PRPs in the response action described above and further made a demand against the Company and other PRPs for reimbursement of approximately $.85 million in costs EPA had incurred in responding to conditions at the site.
The PRP Group is attempting to form a larger group of PRPs to undertake the remedial response, pay EPA response expenses and obtain reimbursement for the $3 million it spent on the EE/CA. Representatives of the Company have been in contact with EPA and the PRP Group and have evaluated the merits of participation with the larger group. The Company is entering into an agreement to become a part of the larger PRP Group and will also continue to work with EPA seeking a "de minimis" settlement.
While further investigation is necessary and is continuing, the results thus far suggest that the Company will defend any contribution action from the other PRPs and the EPA but will continue to explore settlement options which appear to be in the overall best interest of the Company. The Company has yet to determine whether insurance proceeds are available to offset potential costs for the remediation or other expenses which might be required by the Company at this site.
The Parker Landfill is a superfund site located in Lyndonville, Vermont. In 1989, the Company received an information request from the EPA seeking to determine if the Company sent any hazardous substances to the site. An investigation conducted at the time concluded general trash was occasionally sent to the site but the Company had not sent hazardous substances to the site. In May of 1994, the Company received a second request seeking additional information regarding disposal practices. A renewed investigation by the Company again concluded no significant amounts of hazardous substances were sent to the site. Last summer, EPA also announced its proposed preferred remedy for this site with an estimated total present net worth cost of $28.2 million. Final selection of a remedy is anticipated later this year. Thus far, the Company is considered a PIP, not a PRP, for the site. The Company has complied with the information request and will monitor EPA activities at the site.
The Trafton-Hoisington Landfill was a municipal and industrial landfill in the Town of Windsor, Vermont. The site is presently a state lead site although placement on the National Priorities List remains a possibility. The state of Vermont has reached an agreement with a small group of PRPs to conduct a site investigation. The Company was contacted by these PRPs seeking contribution toward the cost of the site investigation. The Company conducted an investigation and concluded no significant amounts of hazardous substances were sent to the site. The Company has advised the PRPs it will not voluntarily contribute under these circumstances.
At this time, the Company does not believe these sites represent the potential for a material adverse effect on its financial condition or results of operations but will continue to monitor activities at the sites.
The Company is not subject to any pending or threatened litigation with respect to any other sites where remediation expenses could be material, nor has the EPA or other state or Federal agency sought contribution from the Company for the study or remediation of any such sites.
Dividend restrictions The indentures relating to long-term debt and the Articles of Association contain certain restrictions on the payment of cash dividends on capital stock. Under the most restrictive of such provisions, approximately $45 million of retained earnings was not subject to dividend restriction at December 31, 1994.
Leases and support agreements The Company participated with other electric utilities in the construction of the Phase I Hydro-Quebec transmission facilities in northeastern Vermont, which were completed at a total cost of approximately $140 million. Under a support agreement relating to the Company's participation in the facilities, the Company is obligated to pay its 4.42% share of Phase I Hydro-Quebec capital costs over a 20-year recovery period through and including 2006. The Company also participated in the construction of Phase II Hydro-Quebec transmission facilities constructed throughout New England, which were placed in service in November 1990 with a total cost of approximately $487 million. Under a similar support agreement, the Company is obligated to pay its 5.132% share of Phase II Hydro-Quebec capital costs over a 25-year recovery period through and including 2015. All costs under these support agreements are recorded as purchased transmission expense in accordance with the Company's rate-making policies. Future minimum payments will be approximately $3.2 million for each year from 1995 through 2015 and will decline thereafter. The Company's percentage shares of the net capital cost of these facilities, totaling approximately, $21.6 million, are classified in the accompanying Consolidated Balance Sheet as "Utility Plant" and "Long-term Lease Arrangements" (current and non-current).
Minimum rental commitments of the Company under non-cancelable leases as of December 31, 1994, are not material. Total rental expense entering into the determination of net income, consisting principally of vehicle and equipment rentals, was approximately $3.0 million, $3.1 million and $3.3 million for the years 1992 through 1994, respectively.
Legal proceeding On December 30, 1994, the Company and its board of directors were named as defendants in a complaint filed in the United States District Court for the District of Vermont by three shareholders. The complaint alleges, among other things, (i) that F. Ray Keyser, Jr., Chairman of the Company's board of directors, violated Section 8 of the Clayton Act, 15 U.S.C. Subchapter 19, which precludes certain interlocking directorships, (ii) that Mr. Keyser violated his fiduciary duties to the Company's stockholders by acquiring and operating a series of businesses in competition with the Company without offering those business opportunities to the Company, (iii) that the remaining individual defendants violated their fiduciary duties to the Company's stockholders by failing to analyze, or to cause management to analyze, diversification into propane and fossil fuels, and by failing to make the Company an effective competitor of alternative fuel companies, and (iv) that the Company violated the applicable provision of the Vermont General Corporation Law by failing to provide a list of the Company's stockholders. The complaint seeks an unspecified amount of damages (including treble damages against Mr. Keyser), attorney's fees and costs, a list of the Company's stockholders, and a court order to enjoin the defendants from alleged continuing violations of the law. Each of the individual defendants and the Company itself deny the allegations against them and intend to vigorously defend the complaint.
Note 14 Non-recurring charge
In addition to the write-offs described in Notes 3 and 11 herein, during the fourth quarter of 1994, the Company also wrote-off approximately $2.9 million of costs associated with its proposed new headquarters office building which reduced after tax earnings by approximately $1.7 million.
Note 15 Unaudited quarterly financial information
The following quarterly financial information is unaudited and includes all adjustments consisting of normal recurring accruals which are, in the opinion of management, necessary for a fair statement of results of operations for such periods. Variations between quarters reflect the seasonal nature of the Company's business (dollars in thousands, except per share amounts):
Quarter Ended 12 Months March June September December Ended
Operating revenues $83,885 $57,684 $59,027 $76,562 $277,158 Operating income (loss) $14,367 $ (447) $ 368 $ 6,815 $ 21,103 Net income (loss) $12,608 $(2,003) $ (791) $ 4,986 $ 14,800 Earnings (loss) per share of common stock $1.04 $(.22) $(.11) $.38 $1.08
Operating revenues $85,319 $56,975 $60,994 $76,101 $279,389 Operating income $16,847 $ 260 $ 679 $ 8,260 $ 26,046 Net income (loss) $14,828 $ (920) $ (354) $ 7,738 $ 21,292 Earnings (loss) per share of common stock $1.26 $(.14) $(.09) $.61 $1.64
Item 9.

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 1995 Annual Meeting of Stockholders, consisting of the three nominees listed below, will stand for re-election to a three-year term expiring in 1998. Proxies will be voted (unless otherwise instructed) in favor of the election of the three nominees as indicated in the table below. While it is not anticipated that any of the persons listed will be unable to serve as a director, if that should occur the proxies will be voted for such other person or persons as the present Board of Directors shall determine.
The following table sets forth certain information regarding the three nominees for Director, as well as all Directors presently serving on the Board whose terms will expire after the 1995 Annual Meeting. Each of the individuals listed in the table has been employed by the firm or has had the occupation set forth under his or her name for the past five years. In general, the business experience of each of these persons during this time was typical of a person engaged in the principal occupation listed for each.
Served as Director Principal Occupation and Name and Age Since Business Experience
Nominees whose terms will expire in 1998:
Luther F. Hackett - 61 1979 President, Hackett, Valine & MacDonald, Inc., Burlington, Vermont (Insurance Agents)
F. Ray Keyser, Jr. - 67 1980 Chairman of the Board of Central Vermont Public Service Corporation, Of Counsel, Keyser, Crowley, Meub, Layden, Kulig & Sullivan, P.C. Rutland, Vermont (Lawyers)
Gordon P. Mills - 58 1980 Chairman, EHV-Weidmann Industries, Inc., St. Johnsbury, Vermont (Manufacturer of Electric Transformer Insulation)
Directors whose terms will expire in 1997:
Frederic H. Bertrand - 58 1984 Chairman of the Board and Chief Executive Officer, National Life Insurance Co. Montpelier, Vermont
Mary Alice McKenzie - 37 1992 President and Chief Executive Officer, John McKenzie Packing Co., Inc. Burlington, Vermont (Manufacturer of Meat Products)
Robert D. Stout - 68 1985 Retired President and Chief Executive Officer, Putnam Memorial Health Corporation, Bennington, Vermont Served as Director Principal Occupation and Name and Age Since Business Experience
Directors whose terms will expire in 1996:
Robert P. Bliss, Jr. - 71 1973 President, Bob Bliss, Ltd. St. Albans, Vermont (Insurance Industry Consultants)
Elizabeth Coleman - 57 1990 President, Bennington College, Bennington, Vermont
Preston Leete Smith - 64 1977 Chief Executive Officer, S-K-I Ltd., West Lebanon, New Hampshire (Ski Business)
Thomas C. Webb - 60 1986 President and Chief Executive Officer, Central Vermont Public Service Corporation, Rutland, Vermont
Executive Officers of the Registrant:
Name and Age Office Officer Since
Thomas C. Webb, 60 President and Chief Executive Officer 1985
Robert H. Young, 47 Executive Vice President and Chief Operating Officer 1987
Robert de R. Stein, 45 Senior Vice President-Energy Resources and External Markets 1988
Frederick S. Potter, 49 Vice President-Finance & Administration and Principal Financial Officer 1994
Jacquel-Anne Chouinard, 55 Vice President-Human Resources 1986
Thomas J. Hurcomb, 57 Vice President-Marketing and Public Affairs 1975
Robert G. Kirn, 43 Vice President-Engineering and Operations 1991
William J. Deehan, 42 Assistant Vice President-Rates and Economic Analysis 1991
Jonathan W. Booraem, 56 Treasurer 1984
Joseph M. Kraus, 40 Secretary and General Counsel 1987
James M. Pennington, 39 Controller and Principal Accounting Officer 1993
Mr. Webb joined the Company in 1985 as Executive Vice President - Finance and Administration and in 1986 was also designated Chief Executive Officer. He was elected Director, President and Chief Executive Officer on July 1, 1986.
Mr. Young joined the Company in 1987 as Vice President - Finance and Administration. Mr. Young was named Senior Vice President - Finance and Administration in 1988, and in 1993 was elected Executive Vice President and Chief Operating Officer.
Mr. Stein joined the Company in 1988 as Assistant Vice President - Energy Planning. Mr. Stein was elected Vice President - Energy Supply Planning and Engineering effective January 1, 1990, and Senior Vice President - Engineering and Energy Resources in 1993 and assumed his present position in 1994.
Mr. Potter joined the Company in 1994 and has served as Vice President - Finance and Administration and Principal Financial Officer since that time. From 1991-1994 he was Vice President at DQE, Inc. and President of its wholly owned subsidiary, Duquesne Enterprises, Inc. During 1989-1990 he was a senior investment banker with Bear, Stearns & Co. Inc.
Ms. Chouinard joined the Company in 1985 as Director - Human Resources. She was elected Assistant Vice President - Human Resources in 1986 and assumed her present position in 1988.
Mr. Hurcomb joined the Company in 1967 in the Marketing and Customer Service area. He was elected Vice President - External Affairs in 1975, and Vice President - Marketing and Public Affairs in 1993.
Mr. Kirn joined the Company in 1991 as Vice President - Division Operations and assumed his present position in 1994. From 1979 to 1991, he was employed by New York State Electric & Gas Corporation. He served as Operations Manager of the Lancaster Division Electric from 1988 until 1991.
Mr. Deehan joined the Company in 1985. Prior to being elected to his present position, he served as Director of Rate Administration and Forecasting.
Mr. Booraem has been with the Company since 1969. Prior to being elected Treasurer in 1984, he was Director of Finance & Planning.
Mr. Kraus joined the Company in 1981 as Assistant Corporate Counsel. He was named Associate Corporate Counsel in 1983 and Senior Corporate Counsel in 1987. He was also elected Corporate Secretary and Senior Corporate Counsel in 1987 and Corporate Secretary and General Counsel effective January 1, 1994.
Mr. Pennington joined the Company in 1989 as Director of Taxes. He was named Director of Taxes and Plant Accounting in 1990. Mr. Pennington was designated Acting Controller effective July 19, 1992, and was elected Controller and named Principal Accounting Officer in 1993.
The term of each officer is for one year or until a successor is elected.
Item 11.

Item 11. Executive Compensation.
The following table sets forth all cash compensation paid or to be paid by the Company and its subsidiaries, as well as the number of stock option awards earned during the last three fiscal years by the Company's Chief Executive Officer and the four other most highly compensated executive officers whose salary and bonus for services rendered to the Company and its subsidiaries in all capacities for 1994 exceeded $100,000.
I. Summary Compensation Table
Long Term Compensation Annual Compensation Awards - ------------------------------------------------------ ------------ (a) (b) (c) (d) (g) (i) Securities Underlying Option/ All Other Name and Principal Salary Bonus SARs Compensation Position Year ($) 1/ ($)2/ (#) ($) 3/ - ---------------------- ---- ------- ------ ------------ --------- A. Thomas C. Webb 1994 260,759 0 8,000/0 7,946 President and Chief 1993 248,755 67,183 8,000/0 12,453 Executive Officer 1992 244,694 73,000 6,000/0 17,850
B. Robert H. Young 1994 153,756 0 6,000/0 4,927 Executive Vice President 1993 141,769 35,995 6,000/0 4,533 and Chief Operating 1992 130,667 34,073 4,500/0 4,363 Officer
C. Robert de R. Stein 1994 119,606 0 4,500/0 4,873 Senior Vice President- 1993 114,677 16,804 4,500/0 3,988 Energy Resources and 1992 105,473 18,728 3,000/0 3,472 External Markets
D. Thomas J. Hurcomb 1994 104,115 0 3,000/0 4,534 Vice President 1993 98,382 15,606 3,000/0 4,996 Marketing and 1992 98,649 17,766 3,000/0 4,355 Public Affairs
E. Robert G. Kirn 1994 98,201 0 3,000/0 4,264 Vice President - 1993 93,736 15,750 3,000/0 3,574 Engineering and 1992 93,465 19,869 3,000/0 1,751 Operations
1/ - 1993 and 1994 include compensation deferred at the election of all executive officers named, and directors' retainers and fees earned from VELCO by Mr. Webb. - 1992 calendar year includes 53 pay periods. - Includes compensation for services performed by Mr. Webb for Vermont Yankee and by Mr. Stein for VELCO for which the Company was reimbursed.
2/ - Includes incentive bonuses awarded by Catamount Energy Corporation, a wholly owned subsidiary, in 1992 and 1993 as follows: For A: 1993 - $10,000, 1992 - $5,000, for B: 1993 - $10,000, 1992 - $5,000. - Includes relocation bonus for E: 1992 - $5,000.
3/ - The total amounts shown in this column for the last fiscal year are comprised as follows: (i) Company matching contributions to the Employee Savings and Investment Plan includes for A: $5,914; for B: $4,613; for C: $4,647; for D: $3,968; for E: $3,928. (ii) Taxable term cost on executive split-dollar insurance. (An insurance plan that gives both employer and employee an interest in the policy death benefit on the employee's life.) For A: $2,032; for B: $314; for C: $226; for D: $566; for E: $336.
Stock Options.
The following table sets forth stock options granted to the Company's Chief Executive Officer and the four other most highly compensated executive officers during 1994 under the Company's 1988 Stock Option Plan for Key Employees. Under SEC regulations, companies are required to project an estimate of appreciation of the underlying shares of stock during the option term. The Company has chosen the Black-Scholes model formula approved by the SEC. However, the ultimate value will depend on the market value of the Company's stock at a future date, which may or may not correspond to the projections below.
II. Options/SAR Grants Table
Option/SAR Grants in Last Fiscal Year
Grant Date Individual Grants Value - ------------------ ---------- ---------- -------- ------- ---------- % of Number of Total Securities Options/ Underlying SARs Options/ Granted to Exercise Grant SARs Employees Or Base Expira- Date Granted In Fiscal Price tion Present Name (#) 1/ Year ($/Sh) Date Value 2/ - ------------------ ---------- ---------- -------- ------- ---------- Thomas C. Webb 8,000/0 21.1% $18.4375 5/3/04 $13,920
Robert H. Young 6,000/0 15.8 18.4375 5/3/04 10,440
Robert de R. Stein 4,500/0 11.8 18.4375 5/3/04 7,830
Thomas J. Hurcomb 3,000/0 7.9 18.4375 5/3/04 5,220
Robert G. Kirn 3,000/0 7.9 18.4375 5/3/04 5,220
1/ A total of 38,000 shares were awarded to all plan participants in 1994. Stock Options are exercisable in whole or in part from the date of the grant for a period of ten years and one day.
2/ Per Black-Scholes model as certified by independent consultant. The assumptions used for the Model are as follows: Volatility- .201 based on quarterly prices for the period of 3/31/88 to 12/31/94; Risk free rate of return-7.2%; Dividend Yield-7.7% over period of 3/31/88 to 12/31/94; and Term of Exercise-10 years.
The following table sets forth stock options exercised by the Company's Chief Executive Officer and the four other most highly compensated executive officers during 1994, and the number and value of all unexercised options at year-end. The value of "in-the-money" options refers to options having an exercise price which is less than the market price of the Company's common stock on December 31, 1994.
III. Option/SAR Exercises and Year-end Value Table
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Value
(a) (b) (c) (d) (e) Number of Securities Value of Underlying Unexercised Unexercised In-the-Money Options/SARs Options/SARs At FY-End (#) FY-End ($) Shares Acquired Value Exercisable/ Exercisable/ Name on Exercise (#) Realized($)1/ Unexercisable Unexercisable - ------------------ --------------- ------------- ------------- -------------
Thomas C. Webb - - 22,000/0 $0/0
Robert H. Young 4,125 $7,391 16,500/0 0/0
Robert de R. Stein - - 19,500/0 0/0
Thomas J. Hurcomb - - 18,000/0 0/0
Robert G. Kirn - - 11,250/0 0/0
1/ The dollar values in columns (c) and (e) are calculated by determining the difference between the fair market value of the securities underlying the options and the exercise or base price of the options at exercise or fiscal year end, respectively.
Deferred Compensation Plan.
Employees of the Company who are officers are eligible to defer receipt of a portion of their compensation pursuant to the Company's Deferred Compensation Plan (the "Plan") for Officers. Also, certain of the Directors of the Company have elected to defer receipt of all or a portion of their fees under a similar plan for Directors.
Under the Plan approved effective January 1, 1990 Directors and Officers of the Company may elect to defer over a 5-year period receipt of a specified amount of compensation or fees otherwise currently payable to them until retirement at age 65 (age 70 for Directors), or until their death, disability, or resignation. Officers may receive a reduced benefit beginning at age 60 with 10 years of service. Amounts deferred are not currently taxable for state and federal income taxes. The benefit is equal to the compensation deferred plus interest credited by the Company. The plan is a defined contribution program under which the Company recovers any costs, including the cost of capital, through the proceeds of the supporting life insurance policies. In addition, if death of a Director occurs before age 70, an additional survivor benefit equal to the annual amount deferred will be paid to the beneficiary each year for fifteen years. This benefit is also financed by life insurance proceeds.
Pension Plan.
The Pension Plan of Central Vermont Public Service Corporation and Its Subsidiaries (the "Plan") is a defined benefit plan which covers employees, among others, who are officers. The Company pays the full cost of the Plan.
The table below shows the annual amounts payable under the present provisions of the Plan as amended through December 31, 1994, based on Final Average Earnings for various years of service, assuming the employee would retire at age 65 in 1995.
________ (1) Internal Revenue Code Section 401(a)(17) limits earnings used to calculate qualified plan benefits to $150,000 for 1994.
Final Average Earnings is the highest five-year average of consecutive years' Base Salary (item (c) from the Summary Compensation Table with the exclusion of Mr. Webb s retainer and fees from VELCO) over an employee's career with the Company.
The amounts above are payable for the life of the retiree only, and would be reduced on an actuarial basis if survivor options were chosen. In addition, no Social Security offset applies to amounts above.
The credited years of service at December 31, 1994 under the Plan for those individuals named in the Summary Compensation Table were as follows: Mr. Webb, 10 years; Mr. Young, 7 years, 6 months; Mr. Stein, 6 years, 7 months; Mr. Hurcomb, 27 years and Mr. Kirn, 3 years, 8 months.
Officers' Insurance and Supplemental Retirement Plan
The Officers' Insurance and Supplemental Retirement Plan (the "Plan") is designed to supplement the retirement benefits available to the Company's officers. The Plan is a part of the Company's overall strategy for attracting and maintaining top managerial talent in the utility industry. Under this Plan, the individuals named in the Summary Compensation Table are covered, while employed, by life insurance at the following multiple of salary: Mr. Webb, 4 times; Messrs. Young, Stein, Hurcomb and Kirn, 3 times.
Under the Plan, each officer is entitled to receive, upon his or her retirement at age 65, fifteen annual payments in amounts equal to a specified percentage of his or her final year's Base Salary (item (c) from the Summary Compensation Table with the exclusion of Mr. Webb s retainer and fees from VELCO). A reduced benefit is available at age 60 for officers who attain age 55 with ten years of service. A paid-up life insurance of $100,000 is also provided to vested retirees under this Plan.
The applicable percentages for the individuals named in Summary Compensation Table are as follows: Mr. Webb, 44.5%; Messrs. Young, Stein, Hurcomb and Kirn, 33%.
Shown below is the estimated Company provided benefit payable under the Plan for those individuals named in the Summary Compensation Table, assuming they were to retire at age 65:
Assumed Final Annual Base Pay 33% 44.5% --------------- ------ ------- $ $ $ --------------- ------ ------- 80,000 26,400 35,600 100,000 33,000 44,500 120,000 39,600 53,400 140,000 46,200 62,300 160,000 52,800 71,200 180,000 59,400 80,100 220,000 72,600 97,900 260,000 85,800 115,700
The Plan is financed through the Company's acquisition of corporate-owned life insurance.
Predecessor Deferred Compensation Plan.
Between 1986 and 1990, the Company allowed officers to defer receipt of compensation in return for fifteen annual payments of a defined benefit amount upon retirement. The Company will pay the difference, if any, between the defined benefit cost and the accumulated value of deferred compensation.
Shown below is the estimated Company-provided benefit, payable at age 65, for those individuals named in the Summary Compensation Table who elected to participate. Since these benefits do not apply to all of the named individuals, they have not been reflected in the foregoing pension table.
Annual Company- Provided Benefit Name Payable at Age 65 ----------- -----------------
Mr. Webb $29,800 Mr. Hurcomb 13,900
Employee Savings and Investment Plan.
Effective January 1, 1985 the Company adopted an Employee Savings and Investment Plan (the Plan ) (also known as a 401(k) Plan) which provides a means for eligible employees to accumulate savings and investment income without payment of current income taxes. Presently any employee of the Company who has completed at least one year of service, as defined in the Plan, is eligible to participate ( Participant ). An eligible employee who elects to participate in the Plan may authorize the Company to contribute to the Plan for his or her account between 1% and 15% of their pre-tax base compensation for each pay period. For 1994, the Plan limits the maximum annual deferral to $9,240 per Participant. This maximum is adjusted annually for inflation by the Internal Revenue Service. The Company matches 100% of the first 4% of the compensation the Participant contributes to the Plan. A Participant may direct the investment of his or her Plan account among five funds specified in the Plan and is at all times fully vested in his or her Plan account. Generally, distribution of employee contributions is deferred until the Participant's death, disability, retirement or other termination of employment, except in cases of financial hardship. Matching employer contributions, however, may be withdrawn by the Participant at any time and for any reason, provided either the amount withdrawn has been in the Plan for at least two years or the Participant has been a member of the Plan for at least 5 years. Such in-service withdrawals are generally subject to ordinary income tax and an additional 10% tax plus a mandatory 20% rollover tax withholding effective January 1, 1993. Distribution of Plan benefits may be in the form of cash, an annuity, or in certain circumstances, Common Stock of the Company. Amounts voluntarily deferred by the five highest paid executive officers are included in compensation listed in Item (c) of the Summary Compensation Table. Matching Company contributions credited to the Plan accounts of the individuals referred to during 1994 are set forth in Column 4, Item (i) in the Summary Compensation Table.
Contracts with Management.
The Company has entered into severance compensation agreements with Messrs. Webb, Young, Stein, Hurcomb, Kirn and six other officers of the Company. The agreements have a term of five years provision for renewal. They provide that in the event of termination of employment, or a significant change in employment status as defined in the agreement, within three years following a change in control of the Company, Messrs. Webb, Young, Stein, Hurcomb, Kirn and three other executive officers will receive 2.999 times and three other officers will receive two times their average annual compensation for the preceding five or fewer years of service and certain legal fees and expenses incurred as a result of termination of employment.
The provisions of the agreement do not apply if the officer retires, dies, or is disabled, voluntarily resigns, or is dismissed for cause. In exchange for agreeing to provide consulting services as requested by the Company for one year and refraining from working in competition with, or for a competitor of the Company for three years, the agreement permits continued participation in and retention of benefits under the Deferred Compensation Plan, Officers' Insurance and Supplemental Retirement Plans, and health and disability plans. The extent of these provisions depends on an individual's participation and circumstances, and is specified in each agreement. Those seven officers with less than 10 years of service would receive a payment actuarially equivalent to benefits received under the Company's pension plan at age 65 with ten years of service, less any benefit paid under the pension plan. The agreements also provide for the payment to officers of an amount sufficient to offset any federal excise tax on the termination payments under Section 4999 of the Internal Revenue Code. Non-qualified stock options not immediately exercisable will become exercisable in the event of a change of control of the Company as defined in the Plan.
A change of control occurs under the agreement when (1) any person, corporation, partnership or group acquires 20% or more of the combined voting power of the Company's outstanding securities; (2) if those members constituting a majority of the Directors at any given date no longer constitute a majority of the Directors at the end of a period of two consecutive years thereafter (unless the nomination of each new director was approved by a vote of at least two-thirds of the directors in office who were directors at the beginning of the period); or (3) if a third party acquires ownership or voting power of 10% or more of the outstanding voting securities of the Company, and subsequently is a "public utility holding company" within the meaning of the Public Utility Holding Company Act of 1935, or the Company loses its exemption from or is required to register under that Act.
During 1989, the Board also approved a severance plan in the event of a change of control for key managers of the Company not covered by the above plan. In the event of a change in control as described above and a subsequent discharge from employment within eighteen months for reason other than cause, thirty-two managers will receive a severance payment equal to one year's base salary, outplacement services, and coverage under the Company's medical plan for one year at Company expense.
The Board of Directors believes that such agreements protect the stockholders by ensuring officers and key managers can and will act in stockholders' best interests without regard to personal situations or concerns. The Board also believes that such agreements will better ensure retention and recruitment of high caliber officers and key managers.
Item 12.

Item 12. Security Ownership of Certain Beneficial Owners and Management.
The following table sets forth the number of shares of Common Stock of the Company beneficially owned by each director and nominee director, each of the executive officers named in the Summary Compensation Table and by all the directors, nominee directors and officers as a group as of January 31, 1995.
Shares of Common Stock Name Beneficially Owned (1)(2)(3)(4) -------------------- ----------------------
Frederic H. Bertrand 10,444 (5) Robert P. Bliss, Jr. 10,573 (6) Elizabeth Coleman 9,959 Luther F. Hackett 8,533 (7) Thomas J. Hurcomb 20,773 F. Ray Keyser, Jr. 14,226 (8) Robert G. Kirn 11,456 Mary Alice McKenzie 6,192 (9) Gordon P. Mills 44,606 (10) Preston Leete Smith 8,299 Robert de R. Stein 19,849 Robert D. Stout 11,531 Thomas C. Webb 35,290 Robert H. Young 17,410 All directors and officers as a group (20) 266,525
No Director, nominee for Director or Executive Officer owns any shares of the various classes of the Company's outstanding non-voting preferred stock.
(1) No Director, nominee for Director or executive officer owns beneficially in excess of 1% of CVPS' outstanding Common Stock, except as otherwise indicated in the footnotes to the table, each of the named individual possesses sole voting and investment power over the shares listed.
(2) Includes shares that the named individuals have a right to acquire pursuant to options granted under the 1988 and 1993 Stock Option Plans for Non-Employee Directors as follows: Messrs. Bertrand and Keyser, 9,000 shares; Messrs. Bliss, Mills and Stout, 7,500 shares; Ms. McKenzie and Mr. Smith, 6,000 shares; Ms. Coleman and Mr. Hackett, 4,500 shares.
(3) Includes shares that the named individuals have a right to acquire pursuant to options granted under the 1988 Stock Option Plan for Key Employees as follows: Mr. Hurcomb, 18,000 shares; Mr. Kirn, 11,250 shares; Mr. Stein, 19,500 shares; Mr. Webb, 22,000 shares; Mr. Young, 16,500 shares; and all Executive Officers as a group, 114,250 shares.
(4) Includes shares that the named individuals hold under the Company's Employee Savings and Investment and Employee Stock Ownership Plans as follows: Mr. Hurcomb, 2,759 shares; Mr. Webb, 8,790 shares; and Mr. Young, 310 shares.
(5) Includes 1,444 shares held jointly with his wife over which Mr. Bertrand has voting and investment power.
(6) Includes 150 shares held jointly with his wife over which Mr. Bliss has voting and investment power.
(7) Includes 1,500 shares owned by corporations over which Mr. Hackett has voting and investment power.
(8) Includes 1,476 shares held jointly with his wife and 3,750 shares held in a Keogh Trust over which Mr. Keyser has voting and investment power.
(9) Includes 150 shares held jointly with her husband over which Ms. McKenzie has voting and investment power.
(10) Includes 15,000 shares held in a pension trust over which Mr. Mills has voting and investment power.
The Company knows of no person, entity or group (within the meaning of Section 13(d)(3) of the Securities Exchange Act of 1934) which owns beneficially more than 5% of any class of the Company's outstanding equity securities.
Reports of Beneficial Ownership
Section 16(a) of the Securities Exchange Act of 1934 requires the Company's Directors and Officers to file reports of ownership and changes in ownership of Company securities with the Securities and Exchange Commission and to furnish the Company with copies of all such reports. In making this statement, the Company has relied on copies of reports that have been filed with the Commission.
Section 16(a) of the Securities Exchange Act of 1934 also requires directors, officers and persons who beneficially own more than ten percent (10%) of the Company's stock to file initial reports of ownership and subsequent reports of changes in ownership with the SEC and the NYSE. Based solely on a review of the copies of such reports prepared and filed with the Commission during 1994 by the Company's Executive Officers and Directors, and on written representations that no other reports were required the Company believes its Directors and Executive Officers have complied with all Section 16(a) filing requirements. The Company does not have a ten percent holder.
Item 13.

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)1. The following financial statements for Central Vermont Public Service Corporation and its wholly owned subsidiaries are filed as part of this report: (See Item 8)
1.1 Consolidated Statement of Income, for each of the three years ended December 31, 1994
Consolidated Statement of Cash Flows, for each of the three years ended December 31, 1994
Consolidated Balance Sheet at December 31, 1994 and 1993
Consolidated Statement of Capitalization at December 31, 1994 and 1993
Consolidated Statement of Changes in Common Stock Equity for each of the three years ended December 31, 1994
Notes to Consolidated Financial Statements
(a)2. Financial Statement Schedules:
2.1 Central Vermont Public Service Corporation and its wholly owned subsidiaries:
Schedule II - Reserves for each of the three years ended December 31, 1994
Schedules not included have been omitted because they are not applicable or the required information is shown in the financial statements or notes thereto. Separate financial statements of the Registrant (which is primarily an operating company) have been omitted since they are consolidated only with those of totally held subsidiaries. Separate financial statements of subsidiary companies not consolidated have been omitted since, if considered in the aggregate, they would not constitute a significant subsidiary. Separate financial statements of 50% or less owned persons for which the investment is accounted for by the equity method by the Registrant have been omitted since, if considered in the aggregate, they would not constitute a significant investment.
(a)3. Exhibits (* denotes filed herewith)
Each document described below is incorporated by reference to the appropriate exhibit numbers and the Commission file numbers indicated in parantheses, unless the reference to the document is marked as follows:
* - Filed herewith.
Exhibit 3 Articles of Incorporation and By-Laws
* 3-1 By-Laws, as amended May 3, 1994.
3-2 Articles of Association, as amended August 11, 1992. (Exhibit No. 3-2, 1992 10-K, File No. 1-8222)
Exhibit 4 Instruments defining the rights of security holders, including Indentures
Incorporated herein by reference:
4-1 Mortgage dated October 1, 1929, between the Company and Old Colony Trust Company, Trustee, securing the Company's First Mortgage Bonds. (Exhibit B-3, File No. 2-2364)
4-2 Supplemental Indenture dated as of August 1, 1936, supplemental to 4-1. (Exhibit B-4, File No. 2-2364)
4-3 Copy of Supplemental Indenture dated as of November 15, 1943, supplemental to 4-1. (Exhibit B-3, File No. 2-5250)
4-4 Copy of Supplemental Indenture dated as of December 1, 1943, supplemental to 4-1. (Exhibit No. B-4, File No. 2-5250)
4-5 Copy of directors' resolutions adopted December 14, 1943, establishing the Series C Bonds and dealing with other related matters, supplemental to 4-1. (Exhibit B-5, File No. 2-5250)
4-6 Copy of Supplemental Indenture dated as of April 1, 1944 supplemental to 4-1. (Exhibit No. B-6, File No. 2-5466)
4-7 Copy of Supplemental Indenture dated as of February 1, 1945, supplemental to 4-1. (Exhibit 7.6, File No. 2-5615) (22-385)
4-8 Directors' resolutions adopted April 9, 1945, establishing the Series D Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 7.8, File No. 2-5615 (22-385)
4-9 Copy of Supplemental Indenture dated as of September 2, 1947, supplemental to 4-1. (Exhibit 7.9, File No. 2-7489)
4-10 Copy of Supplemental Indenture dated as of July 15, 1948, and directors' resolutions establishing the Series E Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 7.10, File No. 2-8388)
4-11 Copy of Supplemental Indenture dated as of May 1, 1950, and directors' resolutions establishing the Series F Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 7.11, File No. 2-8388)
4-12 Copy of Supplemental Indenture dated August 1, 1951, and and directors'resolutions, establishing the Series G Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 7.12, File No. 2-9073)
4-13 Copy of Supplemental Indenture dated May 1, 1952, and directors' resolutions, establishing the Series H Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 4.3.13, File No. 2-9613)
4-14 Copy of Supplemental Indenture dated as of July 10, 1953, supplemental to 4-1. (July, 1953 Form 8-K, File No. 1-8222)
4-15 Copy of Supplemental Indenture dated as of June 1, 1954, and directors' resolutions establishing the Series K Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 4.2.16, File No. 2-10959)
4-16 Copy of Supplemental Indenture dated as of February 1, 1957 and directors' resolutions establishing the Series L Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 4.2.16, File No. 2-13321)
4-17 Copy of Supplemental Indenture dated as of March 15, 1960, supplemental to 4-1. (March, 1960 Form 8-K, File No. 1-8222)
4-18 Copy of Supplemental Indenture dated as of March 1, 1962, supplemental to 4-1. (March, 1962 Form 8-K, File No. 1-8222)
4-19 Copy of Supplemental Indenture dated as of March 2, 1964, supplemental to 4-1. (March, 1964 Form 8-K, File No, 1-8222)
4-20 Copy of Supplemental Indenture dated as of March 1, 1965, and directors' resolutions establishing the Series M Bonds and dealing with other matters, supplemental to 4-1. (April, 1965 Form 8-K, File No. 1-8222)
4-21 Copy of Supplemental Indenture dated as of December 1, 1966, and directors' resolutions establishing the Series N Bonds and dealing with other matters, supplemental to 4-1. (January, 1967 Form 8-K, File No. 1-8222)
4-22 Copy of Supplemental Indenture dated as of December 1, 1967, and directors' resolutions establishing the Series O Bonds and dealing with other matters, supplemental to 4-1. (December, 1967 Form 8-K, File No. 1-8222)
4-23 Copy of Supplemental Indenture dated as of July 1, 1969, and directors' resolutions establishing the Series P Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B.23, July, 1969 Form 8-K, File No. 1-8222)
4-24 Copy of Supplemental Indenture dated as of December 1, 1969, and directors' resolutions establishing the Series Q Bonds January, and dealing with other matters, supplemental to 4-1. (Exhibit B.24, January, 1970 Form 8-K, File No. 1-8222)
4-25 Copy of Supplemental Indenture dated as of May 15, 1971, and directors' resolutions establishing the Series R Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B.25, May, 1971, Form 8-K, File No. 1-8222)
4-26 Copy of Supplemental Indenture dated as of April 15, 1973, and directors' resolutions establishing the Series S Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B.26, May, 1973, Form 8-K, File No. 1-8222)
4-27 Copy of Supplemental Indenture dated as of April 1, 1975, and directors' resolutions establishing the Series T Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B.27, April, 1975, Form 8-K, File No. 1-8222)
4-28 Copy of Supplemental Indenture dated as of April 1, 1977, modifying 4-1. (Exhibit 2.42, File No. 2-58621)
4-29 Copy of Supplemental Indenture dated as of July 29, 1977, and directors' resolutions establishing the Series U, V, W, and X Bonds and dealing with other matters, supplemental to 4-1. (Exhibit 2.43, File No. 2-58621)
4-30 Copy of Thirtieth Supplemental Indenture dated as of September 15, 1978, and directors' resolutions establishing the Series Y Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B-30, 1980 Form 10-K, File No. 1-8222)
4-31 Copy of Thirty-first Supplemental Indenture dated as of September 1, 1979, and directors' resolutions establishing the Series Z Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B-31, 1980 Form 10-K, File No. 1-8222)
4-32 Copy of Thirty-second Supplemental Indenture dated as of June 1, 1981, and directors' resolutions establishing the Series AA Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B-32, 1981 Form 10-K, File No. 1-8222)
4-45 Copy of Thirty-third Supplemental Indenture dated as of August 15, 1983, and directors' resolutions establishing the Series BB Bonds and dealing with other matters, supplemental to 4-1. (Exhibit B-45, 1983 Form 10-K, File No. 1-8222)
4-46 Copy of Bond Purchase Agreement between Merrill, Lynch, Pierce, Fenner & Smith, Inc., Underwriters and The Industrial Development Authority of the State of New Hampshire, issuer and Central Vermont Public Service Corporation. (Exhibit B-46, 1984 Form 10-K, File No. 1-8222)
4-47 Copy of Thirty-Fourth Supplemental Indenture dated as of January 15, 1985, and directors' resolutions establishing the Series CC Bonds and Series DD Bonds and matters connected therewith, supplemental to 4-1. (Exhibit B-47, 1985 Form 10-K, File No. 1-8222)
4-48 Copy of Bond Purchase Agreement among Connecticut Development Authority and Central Vermont Public Service Corporation with E. F. Hutton & Company Inc. dated December 11, 1985. (Exhibit B-48, 1985 Form 10-K, File No. 1-8222)
4-49 Stock-Purchase Agreement between Vermont Electric Power Company, Inc. and the Company dated August 11, 1986 relative to purchase of Class C Preferred Stock. (Exhibit B-49, 1986 Form 10-K, File No. 1-8222)
4-50 Copy of Thirty-Fifth Supplemental Indenture dated as of December 15, 1989 and directors' resolutions establishing the Series EE, Series FF and Series GG Bonds and matters connected therewith, supplemental to 4-1. (Exhibit 4-50, 1989 Form 10-K, File No. 1-8222)
4-51 Copy of Thirty-Sixth Supplemental Indenture dated as of December 10, 1990 and directors' resolutions establishing the Series HH Bonds and matters connected therewith, supplemental to 4-1. (Exhibit 4-51, 1990 Form 10-K, File No. 1-8222)
4-52 Copy of Thirty-Seventh Supplemental Indenture dated December 10, 1991 and directors' resolutions establishing the Series JJ Bonds and matters connected therewith, supplemental to 4-1. (Exhibit 4-52, 1991 Form 10-K, File No. 1-8222)
4-53 Copy of Thirty-Eight Supplemental Indenture dated December 10, 1993 establishing Series KK, LL, MM, NN, OO supplemental to B-1 (Exhibit 4-53, 1993 Form 10-K, File No. 1-8222)
Exhibit 10 Material Contracts (*Denotes filed herewith)
Incorporated herein by reference:
10.l Copy of firm power Contract dated August 29, 1958, and supplements thereto dated September 19, 1958, October 7, 1958, and October 1, 1960, between the Company and the State of Vermont (the "State"). (Exhibit C-1, File No. 2-17184)
10.1.1 Agreement setting out Supplemental NEPOOL Understandings dated as of April 2, 1973. (Exhibit C-22, File No. 5-50198)
10.2 Copy of Transmission Contract dated June 13, 1957, between Velco and the State, relating to transmission of power. (Exhibit 10.2, 1993 Form 10-K, File No. 1-8222)
10.2.1 Copy of letter agreement dated August 4, 1961, between Velco and the State. (Exhibit C-3, File No. 2-26485)
10.2.2 Amendment dated September 23, 1969. (Exhibit C-4, File No. 2-38161)
10.2.3 Amendment dated March 12, 1980. (Exhibit C-92, 1982 Form 10-K, File No. 1-8222)
10.2.4 Amendment dated September 24, 1980. (Exhibit C-93, 1982 Form 10-K, File No. 1-8222)
10.3 Copy of subtransmission contract dated August 29, 1958, between Velco and the Company (there are seven similar contracts between Velco and other utilities). (Exhibit 10.3, 1993 Form 10-K, Form No. 1-8222)
10.3.1 Copies of Amendments dated September 7, 196l, November 2, 1967, March 22, 1968, and October 29, 1968. (Exhibit C-6, File No. 2-32917)
10.3.2 Amendment dated December 1, 1972. (Exhibit 10.3.2, 1993 Form 10-K, File No. 1-8222)
10.4 Copy of Three-Party Agreement dated September 25, 1957, between the Company, Green Mountain and Velco. (Exhibit C-7, File No. 2-17184)
10.4.1 Superseding Three Party Power Agreement dated January 1, 1990. (Exhibit 10-201, 1990 Form 10-K, File No. 1-8222)
10.4.2 Agreement Amending Superseding Three Party Power Agreement dated May 1, 1991. (Exhibit 10.4.2, 1991 Form 10-K, File No. 1-8222)
10.5 Copy of firm power Contract dated December 29, 1961, between the Company and the State, relating to purchase of Niagara Project power. (Exhibit C-8, File No. 2-26485)
10.5.1 Amendment effective as of January 1, 1980. (Exhibit 10.5.1, 1993 Form 10-K, File No. 1-8222)
10.6 Copy of agreement dated July 16, 1966, and letter supplement dated July 16, 1966, between Velco and Public Service Company of New Hampshire relating to purchase of single unit power from Merrimack II. (Exhibit C-9, File No. 2-26485)
10.6.1 Copy of Letter Agreement dated July 10, 1968, modifying Exhibit A. Exhibit C-10, File No. 2-32917)
10.7 Copy of Capital Funds Agreement between the Company and Vermont Yankee dated as of February 1, 1968. (Exhibit C-11, File No. 70-4611)
10.7.1 Copy of Amendment dated March 12, 1968. (Exhibit C-12, File No. 70-4611)
* 10.7.2 Copy of Amendment dated September 1, 1993
10.8 Copy of Power Contract between the Company and Vermont Yankee dated as of February 1, 1968. (Exhibit C-13, File No. 70-4591)
10.8.1 Amendment dated April 15, 1983. (10.8.1, 1993 Form 10-K, File No. 1-8222)
10.8.2 Copy of Additional Power Contract dated February 1, 1984. (Exhibit C-123, 1984 Form 10-K, File No. 1-8222)
10.8.3 Amendment No. 3 to Vermont Yankee Power Contract, dated April 24, 1985. (Exhibit 10-144, 1986 Form 10-K, File No. 1-8222)
10.8.4 Amendment No. 4 to Vermont Yankee Power Contract, dated June 1, 1985. (Exhibit 10-145, 1986 Form 10-K, File No. 1-8222)
10.8.5 Amendment No. 5 dated May 6, 1988. (Exhibit 10-179, 1988 Form 10-K, File No. 1-8222)
10.8.6 Amendment No. 6 dated May 6, 1988. (Exhibit 10-180, 1988 Form 10-K, File No. 1-8222)
10.8.7 Amendment No. 7 dated June 15, 1989. (Exhibit 10-195, 1989 Form 10-K, File No. 1-8222)
10.9 Copy of Capital Funds Agreement between the Company and Maine Yankee dated as of May 20, 1968. (Exhibit C-14, File No. 70-4658)
10.9.1 Amendment No. 1 dated August 1, 1985. (Exhibit C-125, 1984 Form 10-K, File No. 1-8222)
10.10 Copy of Power Contract between the Company and Maine Yankee dated as of May 20, 1968. (Exhibit C-15, File No. 70-4658)
10.10.1 Amendment No. 1 dated March 1, 1984. (Exhibit C-112, 1984 Form 10-K, File No. 1-8222)
10.10.2 Amendment No. 2 effective January 1, 1984. (Exhibit C-113, 1984 Form 10-K, File No. 1-8222)
10.10.3 Amendment No. 3 dated October 1, 1984. (Exhibit C-114, 1984 Form 10-K, File No. 1-8222)
10.10.4 Additional Power Contract dated February 1, 1984. (Exhibit C-126, 1985 Form 10-K, File No. 1-8222)
10.11 Copy of Agreement dated January 17, 1968, between Velco and Public Service Company of New Hampshire relating to purchase of additional unit power from Merrimack II. (Exhibit C-16, File No. 2-32917)
10.12 Copy of Agreement dated February 10, 1968 between the Company and Velco relating to purchase by Company of Merrimack II unit power. (There are 25 similar agreements between Velco and other utilities.) (Exhibit C-17, File No. 2-32917)
10.13 Copy of Three-Party Power Agreement dated as of November 21, 1969, among the Company, Velco, and Green Mountain relating to purchase and sale of power from Vermont Yankee Nuclear Power Corporation. (Exhibit C-18, File No. 2-38161)
10.13.1 Amendment dated June 1, 1981. (Exhibit 10.13.1, 1993 Form 10-K, File No. 1-8222)
10.14 Copy of Three-Party Transmission Agreement dated as of November 21, 1969, among the Company, Velco, and Green Mountain providing for transmission of power from Vermont Yankee Nuclear Power Corporation. (Exhibit C-19, File No. 2-38161)
10.14.1 Amendment dated June 1, 1981. (Exhibit 10.14.1, 1993 Form 10-K, File No. 1-8222)
10.15 Copy of Stockholders Agreement dated September 25, 1957, between the Company, Velco, Green Mountain and Citizens Utilities Company. (Exhibit No. C-20, File No. 70-3558)
10.16 New England Power Pool Agreement dated as of September 1, 1971, as amended to November 1, 1975. (Exhibit C-21, File No. 2-55385)
10.16.1 Amendment dated December 31, 1976. (Exhibit 10.16.1 1993 Form 10-K, File No. 1-8222)
10.16.2 Amendment dated January 23, 1977. (Exhibit 10.16.2, 1993 Form 10-K, File No. 1-8222)
10.16.3 Amendment dated July 1, 1977. (Exhibit 10.16.3, 1993 Form 10-K, File No. 1-8222)
10.16.4 Amendment dated August 1, 1977. (Exhibit 10.16.4, 1993 Form 10-K, File No. 1-8222)
10.16.5 Amendment dated August 15, 1978. (Exhibit 10.16.5, 1993 Form 10-K, File No. 1-8222)
10.16.6 Amendment dated January 31, 1979. (Exhibit 10.16.6, 1993 Form 10-K, File No. 1-8222)
10.16.7 Amendment dated Feburary 1, 1980. (Exhibit 10.16.7, 1993 Form 10-K, File No. 1-8222)
10.16.8 Amendment dated December 31, 1976. (Exhibit 10.16.8, 1993 Form 10-K, File No. 1-8222)
10.16.9 Amendment dated January 31, 1977. (Exhibit 10.16.9, 1993 Form 10-K, File No. 1-8222)
10.16.10 Amendment dated July 1, 1977. (Exhibit 10.16.10, 1993 Form 10-K, File No. 1-8222)
10.16.11 Amendment dated August 1, 1977. (Exhibit 10.16.11, 1993 Form 10-K, File No. 1-8222)
10.16.12 Amendment dated August 15, 1978. (Exhibit 10.16.12, 1993 Form 10-K, File No. 1-8222)
10.16.13 Amendment dated January 31, 1980. (Exhibit 10.16.13, 1993 Form 10-K, File No. 1-8222)
10.16.14 Amendment dated February 1, 1980. (Exhibit 10.16.14, 1993 Form 10-K, File No. 1-8222)
10.16.15 Amendment dated September 1, 1981. (Exhibit 10.16.15, 1993 Form 10-K, File No. 1-8222)
10.16.16 Amendment dated December 1, 1981. (Exhibit 10.16.16, 1993 Form 10-K, File No. 1-8222)
10.16.17 Amendment dated June 15, 1983. (Exhibit 10.16.17, 1993 Form 10-K, File No. 1-8222)
10.16.18 Amendment dated September 1, 1985. (Exhibit 10-160, 1986 Form 10-K, File No. 1-8222)
10.16.19 Amendment dated April 30, 1987. (Exhibit 10-172, 1987 Form 10-K, File No. 1-8222)
10.16.20 Amendment dated March 1, 1988. (Exhibit 10-178, 1988 Form 10-K, File No. 1-8222)
10.16.21 Amendment dated March 15, 1989. (Exhibit 10-194, 1989 Form 10-K, File No. 1-8222)
10.16.22 Amendment dated October 1, 1990. (Exhibit 10-203, 1990 Form 10-K, File No. 1-8222)
10.16.23 Amendment dated September 15, 1992. (Exhibit 10.16.23, 1992 Form 10-K, File No. 1-8222)
10.16.24 Amendment dated May 1, 1993. (Exhibit 10.16.24, 1993 Form 10-K, File No. 1-8222)
10.16.25 Amendment dated June 1, 1993. (Exhibit 10.16.25, 1993 Form 10-K, File No. 1-8222)
* 10.16.26 Amendment dated June 1, 1994.
10.17 Agreement dated October 13, 1972, for Joint Ownership, Construction and Operation of Pilgrim Unit No. 2 among Boston Edison Company and other utilities, including the Company. (Exhibit C-23, File No. 2-45990)
10.17.1 Amendments dated September 20, 1973, and September 15, 1974. (Exhibit C-24, File No. 2-51999)
10.17.2 Amendment dated December 1, 1974. (Exhibit C-25, File No. 2-54449)
10.17.3 Amendent dated February 15, 1975. (Exhibit C-26, File No. 2-53819)
10.17.4 Amendment dated April 30, 1975. (Exhibit C-27, File No. 2-53819)
10.17.5 Amendment dated as of June 30, 1975. (Exhibit C-28, File No. 2-54449)
10.17.6 Instrument of Transfer dated as of October 1, 1974, assigning partial interest from the Company to Green Mountain Power Corporation. (Exhibit C-29, File No. 2-52177)
10.17.7 Instrument of Transfer dated as of January 17, 1975, assigning a partial interest from the Company to the Burlington Electric Department. (Exhibit C-30, File No. 2-55458)
10.17.8 Addendum dated as of October 1, 1974 by which Green Mountain Power Corporation became a party thereto. (Exhibit C-31, File No. 2-52177)
10.17.9 Addendum dated as of January 17, 1975 by which the Burlington Electric Department became a party thereto. (Exhibit C-32, File No. 2-55450)
10.17.10 Amendment 23 dated as of 1975. (Exhibit C-50, 1975 Form 10-K, File No. 1-8222)
10.18 Agreement for Sharing Costs Associated with Pilgrim Unit No.2 Transmission dated October 13, 1972, among Boston Edison Company and other utilities including the Company. (Exhibit C-33, File No. 2-45990)
10.18.1 Addendum dated as of October 1, 1974, by which Green Mountain Power Corporation became a party thereto. (Exhibit C-34, File No. 2-52177)
10.18.2 Addendum dated as of January 17, 1975, by which Burlington Electric Department became a party thereto. (Exhibit C-35, File No. 2-55458)
10.19 Agreement dated as of May 1, 1973, for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units among Public Service Company of New Hampshire and other utilities, including Velco. (Exhibit C-36, File No. 2-48966)
10.19.1 Amendments dated May 24, 1974, June 21, 1974, September 25, 1974, October 25, l974, and January 31, 1975. (Exhibit C-37, File No. 2-53674)
10.19.2 Instrument of Transfer dated September 27, 1974, assigning partial interest from Velco to the Company. (Exhibit C-38, File No. 2-52177)
10.19.3 Amendments dated May 24, 1974, June 21, 1974, and September 25, 1974. (Exhibit C-81, File No. 2-51999)
10.19.4 Amendments dated October 25, 1974 and January 31, 1975. (Exhibit C-82, File No. 2-54646)
10.19.5 Sixth Amendment dated as of April 18, 1979. (Exhibit C-83, File No. 2-64294)
10.19.6 Seventh Amendment dated as of April 18, 1979. (Exhibit C-84, File No. 2-64294)
10.19.7 Eighth Amendment dated as of April 25, 1979. (Exhibit C-85, File No. 2-64815)
10.19.8 Ninth Amendment dated as of June 8, 1979. (Exhibit C-86, File No. 2-64815)
10.19.9 Tenth Amendment dated as of October 10, 1979. (Exhibit C-87, File No. 2-66334 )
10.19.10 Eleventh Amendment dated as of December 15, 1979. (Exhibit C-88, File No.2-66492)
10.19.11 Twelfth Amendment dated as of June 16, 1980. (Exhibit C-89, File No. 2-68168)
10.19.12 Thirteenth Amendment dated as of December 31, 1980. (Exhibit C-90, File No. 2-70579)
10.19.13 Fourteenth Amendment dated as of June 1, 1982.(Exhibit C-104, 1982 Form 10-K, File No. 1-8222)
10.19.14 Fifteenth Amendment dated April 27, 1984. (Exhibit 10-134, 1986 Form 10-K, File No. 1-8222)
10.19.15 Sixteenth Amendment dated June 15, 1984. (Exhibit 10-135, 1986 Form 10-K, File No. 1-8222)
10.19.16 Seventeenth Amendment dated March 8, 1985. (Exhibit 10-136, 1986 Form 10-K, File No. 1-8222)
10.19.17 Eighteenth Amendment dated March 14, 1986. (Exhibit 10-137, 1986 Form 10-K, File No. 1-8222)
10.19.18 Nineteenth Amendment dated May 1, 1986. (Exhibit 10-138, 1986 Form 10-K, File No. 1-8222)
10.19.19 Twentieth Amendment dated September 19, 1986. (Exhibit 10-139, 1986 Form 10-K, File No. 1-8222)
10.19.20 Amendment No. 22 dated January 13, 1989. (Exhibit 10-193, 1989 Form 10-K, File No. 1-8222)
10.20 Transmission Support Agreement dated as of May 1, 1973, among Public Service Company of New Hampshire and other utilities, including Velco, with respect to New Hampshire Nuclear Units. (Exhibit C-39, File No. 248966)
10.21 Sharing Agreement - 1979 Connecticut Nuclear Unit dated September 1, 1973, to which the Company is a party. (Exhibit C-40, File No. 2-50142)
10.21.1 Amendment dated as of August 1, 1974. (Exhibit C-41, File No. 2-51999)
10.21.2 Instrument of Transfer dated as of February 28, 1974, transferring partial interest from the Company to Green Mountain. (Exhibit C-42, File No. 2-52177)
10.21.3 Instrument of Transfer dated January 17, 1975, transferring a partial interest from the Company to Burlington Electric Department. (Exhibit C-43, File No. 2-55458)
10.21.4 Amendment dated May 11, 1984. (Exhibit C-110, 1984 Form 10-K, File No. 1-8222)
10.22 Preliminary Agreement dated as of July 5, 1974, with respect to 1981 Montague Nuclear Generating Units. (Exhibit C-44, File No. 2-51733)
10.22.1 Amendment dated June 30, 1975. (Exhibit C-45, File No. 2-54449)
10.23 Agreement for Joint Ownership, Construction and Operation of William F. Wyman Unit No. 4 dated November 1, 1974, among Central Maine Power Company and other utilities including the Company. (Exhibit C-46, File No. 2-52900)
10.23.1 Amendment dated as of June 30, 1975. (Exhibit C-47, File No. 2-55458)
10.23.2 Instrument of Transfer dated July 30, 1975, assigning a partial interest from Velco to the Company. (Exhibit C-48, File No. 2-55458)
10.24 Transmission Agreement dated November 1, 1974, among Central Maine Power Company and other utilities including the Company with respect to William F. Wyman Unit No. 4. (Exhibit C-49, File No. 2-54449)
10.25 Copy of Power Contract between the Company and Yankee Atomic dated as of June 30, 1959. (Exhibit C-61, 1981 Form 10-K, File No. 1-8222)
10.25.1 Revision dated April 1, 1975. (Exhibit C-61, 1981 Form 10-K, File No. 1-8222)
10.25.2 Amendment dated May 6, 1988. (Exhibit 10-181, 1988 Form 10-K, File No. 1-8222)
10.25.3 Amendment dated June 26, 1989. (Exhibit 10-196, 1989 Form 10-K, File No. 1-8222)
10.25.4 Amendment dated July 1, 1989. (Exhibit 10-197, 1989 Form 10-K, File No. 1-8222)
10.25.5 Amendment dated February 1, 1992 (Exhibit 10.25.5, 1992 Form 10-K, File No. 1-8222)
10.26 Copy of Transmission Contract between the Company and Yankee Atomic dated as of June 30, 1959. (Exhibit C-63, 1981 Form 10-K, File No. 1-8222)
10.27 Copy of Power Contract between the Company and Connecticut Yankee dated as of June 1, 1964. (Exhibit C-64, 1981 Form 10-K, File No. 1-8222)
10.27.1 Supplementary Power Contract dated March 1, 1978. (Exhibit C-94, 1982 Form 10-K, File No. 1-8222)
10.27.2 Amendment dated August 22, 1980. (Exhibit C-95, 1982 Form 10-K, File No. 1-8222)
10.27.3 Amendment dated October 15, 1982. (Exhibit C-96, 1982 Form 10-K, File No. 1-8222)
10.27.4 Second Supplementary Power Contract dated April 30, 1984. (Exhibit C-115, 1984 Form 10-K, File No. 1-8222)
10.27.5 Additional Power Contract dated April 30, 1984. (Exhibit C-116, 1984 Form 10-K, File No. 1-8222)
10.28 Copy of Transmission Contract between the Company and Connecticut Yankee dated as of July 1, 1964. (Exhibit C-65, 1981 Form 10-K, File No. 1-8222)
10.29 Copy of Capital Funds Agreement between the Company and Connecticut Yankee dated as of July 1, 1964. (Exhibit C-66, 1981 Form 10-K, File No. 1-8222)
10.29.1 Copy of Capital Funds Agreement between the Company and Connecticut Yankee dated as of September 1, 1964. (Exhibit C-67, 1981 Form 10-K, File No. 1-8222)
10.30 Copy of Five-Year Capital Contribution Agreement between the Company and Connecticut Yankee dated as of November 1, 1980. (Exhibit C-68, 1981 Form 10-K, File No. 1-8222)
10.31 Form of Guarantee Agreement dated as of November 7, 1981, among certain banks, Connecticut Yankee and the Company, relating to revolving credit notes of Connecticut Yankee. (Exhibit C-69, 1981 Form 10-K, File No. 1-8222)
10.32 Form of Guarantee Agreement dated as of November 13, 1981, between The Connecticut Bank and Trust Company, as Trustee, and the Company, relating to debentures of Connecticut Yankee. (Exhibit C-70, 1981 Form 10-K, File No. 1-8222)
10.33 Form of Guarantee Agreement dated as of November 5, 1981, between Bankers Trust Company, as Trustee of the Vernon Energy Trust, and the Company, relating to Vermont Yankee Nuclear Fuel Sale Agreement. (Exhibit C-71, 1981 Form 10-K, File No. 1-8222)
10.34 Preliminary Vermont Support Agreement re Quebec Interconnection between Velco and among seventeen Vermont Utilities dated May 1, 1981. (Exhibit C-97, 1982 Form 10-K, File No. 1-8222)
10.34.1 Amendment dated June 1, 1982. (Exhibit C-98, 1982 Form 10-K, File No. 1-8222)
10.35 Vermont Participation Agreement for Quebec Interconnection between Velco and among seventeen Vermont Utilities dated July 15, 1982. (Exhibit C-99, 1982 Form 10-K, File No. 1-8222)
10.35.1 Amendment No. 1 dated January 1, 1986. (Exhibit C-132, 1986 Form 10-K, File No. 1-8222)
10.36 Vermont Electric Transmission Company Capital Funds Support Agreement between Velco and among sixteen Vermont Utilities dated July 15, 1982. (Exhibit C-100, 1982 Form 10-K, File No. 1-8222)
10.37 Vermont Transmission Line Support Agreement, Vermont Electric Transmission Company and twenty New England Utilities dated December 1, 1981, as amended by Amendment No. 1 dated June 1, 1982, and by Amendment No. 2 dated November 1, 1982. (Exhibit C-101, 1982 Form 10-K, File No. 1-8222)
10.37.1 Amendment No. 3 dated January 1, 1986. (Exhibit 10-149, 1986 Form 10-K, File No. 1-8222)
10.38 Phase 1 Terminal Facility Support Agreement between New England Electric Transmission Corporation and twenty New England Utilities dated December 1, 1981, as amended by Amendment No. 1 dated as of June 1, 1982 and by Amendment No. 2 dated as of November 1, 1982. (Exhibit C-102, 1982 Form 10-K, File No. 1-8222)
10.39 Power Purchase Agreement between Velco and CVPS dated June 1, 1981. (Exhibit C-103, 1982 Form 10-K, File No. 1-8222)
10.40 Agreement for Joint Ownership, Construction and Operation of the Joseph C. McNeil Generating Station by and between City of Burlington Electric Department, Central Vermont Realty, Inc. and Vermont Public Power Supply Authority dated May 14, 1982. (Exhibit C-107, 1983 Form 10-K, File No. 1-8222)
10.40.1 Amendment No. 1 dated October 5, 1982. (Exhibit C-108, 1983 Form 10-K, File No. 1-8222)
10.40.2 Amendment No. 2 dated December 30, 1983. (Exhibit C-109, 1983 Form 10-K, File No. 1-8222)
10.40.3 Amendment No. 3 dated January 10, 1984. (Exhibit 10-143, 1986 Form 10-K, File No. 1-8222)
10.41 Transmission Service Contract between Central Vermont Public Service Corporation and The Vermont Electric Generation & Transmission Cooperative, Inc. dated May 14, 1984. (Exhibit C-111, 1984 Form 10-K, File No. 1-8222)
10.42 Copy of Highgate Transmission Interconnection Preliminary Support Agreement dated April 9, 1984. (Exhibit C-117, 1984 Form 10-K, File No. 1-8222)
10.43 Copy of Allocation Contract for Hydro-Quebec Firm Power dated July 25, 1984. (Exhibit C-118, 1984 Form 10-K, File No. 1-8222)
10.43.1 Tertiary Energy for Testing of the Highgate HVDC Station Agreement, dated September 20, 1985. (Exhibit C-129, 1985 Form 10-K, File No. 1-8222)
10.44 Copy of Highgate Operating and Management Agreement dated August 1, 1984. (Exhibit C-119, 1986 Form 10-K, File No. 1-8222)
10.44.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-152, 1986 Form 10-K, File No. 1-8222)
10.44.2 Amendment No. 2 dated November 13, 1986. (Exhibit 10-167, 1987 Form 10-K, File No. 1-8222)
10.44.3 Amendment No. 3 dated January 1, 1987. (Exhibit 10-168, 1987 Form 10-K, File No. 1-8222)
10.45 Copy of Highgate Construction Agreement dated August 1, 1984. (Exhibit C-120, 1984 Form 10-K, File No. 1-8222)
10.45.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-151, 1986 Form 10-K, File No. 1-8222)
10.46 Copy of Agreement for Joint Ownership, Construction and Operation of the Highgate Transmission Interconnection. (Exhibit C-121, 1984 Form 10-K, File No. 1-8222)
10.46.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-153, 1986 Form 10-K, File No. 1-8222)
10.46.2 Amendment No. 2 dated April 18, 1985. (Exhibit 10-154, 1986 Form 10-K, File No. 1-8222)
10.46.3 Amendment No. 3 dated February 12, 1986. (Exhibit 10-155, 1986 Form 10-K, File No. 1-8222)
10.46.4 Amendment No. 4 dated November 13, 1986. (Exhibit 10-169, 1987 Form 10-K, File No. 1-8222)
10.46.5 Amendment No. 5 and Restatement of Agreement dated January 1, 1987. (Exhibit 10-170, 1987 Form 10-K, File No. 1-8222)
10.47 Copy of the Highgate Transmission Agreement dated August 1, 1984. (Exhibit C-122, 1984 Form 10-K, File No. 1-8222)
10.48 Copy of Preliminary Vermont Support Agreement Re: Quebec Interconnection - Phase II dated September 1, 1984. (Exhibit C-124, 1984 Form 10-K, File No. 1-8222)
10.48.1 First Amendment dated March 1, 1985. (Exhibit C-127, 1985 Form 10-K, File No. 1-8222)
10.49 Vermont Transmission and Interconnection Agreement between New England Power Company and Central Vermont Public Service Corporation and Green Mountain Power Corporation with the consent of Vermont Electric Power Company, Inc., dated May 1, 1985. (Exhibit C-128, 1985 Form 10-K, File No. 1-8222)
10.50 Service Contract Agreement between the Company and the State of Vermont for distribution and sale of energy from St. Lawrence power projects ("NYPA Power") dated as of June 25, 1985. (Exhibit C-130, 1985 Form 10-K, File No. 1-8222)
10.50.1 Lease and Operating Agreement between the Company and the State of Vermont dated as of June 25, 1985. (Exhibit C-131, 1985 Form 10-K, File No. 1-8222)
10.51 System Sales & Exchange Agreement Between Niagara Mohawk Power Corporation and Central Vermont Public Service Corporation dated October 1, 1986. (Exhibit C-133, 1986 Form 10-K, File No. 1-8222)
10.54 Transmission Agreement between Vermont Electric Power Company, Inc. and Central Vermont Public Service Corporation dated January 1, 1986. (Exhibit 10-146, 1986 Form 10-K, File No. 1-8222)
10.55 1985 Four-Party Agreement between Vermont Electric Power Company, Central Vermont Public Service Corporation, Green Mountain Power Corporation and Citizens Utilities dated July 1, 1985. (Exhibit 10-147, 1986 Form 10-K, File No. 1-8222)
10.55.1 Amendment dated February 1, 1987. (Exhibit 10-171, 1987 Form 10-K, File No. 1-8222)
10.56 1985 Option Agreement between Vermont Electric Power Company, Central Vermont Public Service Corporation, Green Mountain Power Corporation and Citizens Utilities dated December 27, 1985. (Exhibit 10-148, 1986 Form 10-K, File No. 1-8222)
10.56.1 Amendment No. 1 dated September 28, 1988. (Exhibit 10-182, 1988 Form 10-K, File No. 1-8222)
10.56.2 Amendment No. 2 dated October 1, 1991. (Exhibit 10.56.2, 1991 Form 10-K, File No. 1-8222)
* 10.56.3 Amendment No. 3 dated December 31, 1994
10.57 Highgate Transmission Agreement dated August 1, 1984 by and between the owners of the project and the Vermont electric distribution companies. (Exhibit 10-156, 1986 Form 10-K, File No. 1-8222)
10.57.1 Amendment No. 1 dated September 22, 1985. (Exhibit 10-157, 1986 Form 10-K, File No. 1-8222)
10.58 Vermont Support Agency Agreement re: Quebec Interconnection - Phase II between Vermont Electric Power Company, Inc. and participating Vermont electric utilities dated June 1, 1985. (Exhibit 10-158, 1986 Form 10K, File No. 1-8222)
10.58.1 Amendment No. 1 dated June 20, 1986. (Exhibit 10-159, 1986 Form 10-K, File No. 1-8222)
10.59 Indemnity Agreement B-39 dated May 9, 1969 with amendments 1-16 dated April 17, 1970 thru April 16, 1985 between licensees of Millstone Unit No. 3 and the Nuclear Regulatory Commission. (Exhibit 10-161, 1986 Form 10-K, File No. 1-8222)
10.59.1 Amendment No. 17 dated November 25, 1985. (Exhibit 10-162, 1986 Form 10-K, File No. 1-8222)
10.62 Contract for the Sale of 50MW of firm power between Hydro-Quebec and Vermont Joint Owners of Highgate Facilities dated February 23, 1987. (Exhibit 10-173, 1987 Form 10-K, File No. 1-8222)
10.63 Interconnection Agreement between Hydro-Quebec and Vermont Joint Owners of Highgate facilities dated February 23, 1987. (Exhibit 10-174, 1987 Form 10-K, File No. 1-8222)
10.63.1 Amendment dated September 1, 1993 (Exhibit 10.63.1, 1993 Form 10-K, File No. 1-8222)
10.64 Firm Power and Energy Contract by and between Hydro-Quebec and Vermont Joint Owners of Highgate for 500MW dated December 4, 1987. (Exhibit 10-175, 1987 Form 10-K, File No. 1-8222)
10.64.1 Amendment No. 1 dated August 31, 1988. (Exhibit 10-191, 1988 Form 10-K, File No. 1-8222)
10.64.2 Amendment No. 2 dated September 19, 1990. (Exhibit 10-202, 1990 Form 10-K, File No. 1-8222)
10.64.3 Firm Power & Energy Contract dated January 21, 1993 by and between Hydro-Quebec and Central Vermont Public Service Corporation for the sale back of 25 MW of power. (Exhibit 10.64.3, 1992 Form 10-K, File No. 1-8222)
10.64.4 Firm Power & Energy Contract dated January 21, 1993 by and between Hydro-Quebec and Central Vermont Public Service Corporation for the sale back of 50 MW of power. (Exhibit 10.64.4, 1992 Form 10-K, File No. 1-8222)
10.66 Hydro-Quebec Participation Agreement dated April 1, 1988 for 600 MW between Hydro-Quebec and Vermont Joint Owners of Highgate. (Exhibit 10-177, 1988 Form 10-K, File No. 1-8222)
10.67 Sale of firm power and energy (54MW) between Hydro-Quebec and Vermont Utilities dated December 29, 1988. (Exhibit 10-183, 1988 Form 10-K, File No. 1-8222)
10.75 Receivables Purchase Agreement between Central Vermont Public Service Corporation, Central Vermont Public Service Corporation as Service Agent and The First National Bank of Boston dated November 29, 1988. (Exhibit 10-192, 1988 Form 10-K)
10.75.1 Agreement Amendment No. 1 dated December 21, 1988 (Exhibit 10.75.1, 1993 Form 10-K, File No. 1-8222)
10.75.2 Letter Agreement dated December 4, 1989 (Exhibit 10.75.2, 1993 Form 10-K, File No. 1-8222)
10.75.3 Agreement Amendment No. 2 dated November 29, 1990 (Exhibit 10.75.3, 1993 Form 10-K, File No. 1-8222)
10.75.4 Agreement Amendment No. 3 dated November 29, 1991 (Exhibit 10.75.4, 1993 Form 10-K, File No. 1-8222)
10.75.5 Agreement Amendment No. 4 dated November 29, 1992 (Exhibit 10.75.5, 1993 Form 10-K, File No. 1-8222)
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
A 10.68 Stock Option Plan for Non-Employee Directors dated July 18, 1988. (Exhibit 10-184, 1988 Form 10-K, File No. 1-8222)
A 10.69 Stock Option Plan for Key Employees dated July 18, 1988. (Exhibit 10-185, 1988 Form 10-K, File No. 1-8222)
A 10.70 Officers Supplemental Insurance Plan authorized July 9, 1984. (Exhibit 10-186, 1988 Form 10-K, File No. 1-8222)
A 10.71 Officers Supplemental Deferred Compensation Plan dated November 4, 1985. (Exhibit 10-187, 1988 Form 10-K, File No. 1-8222)
A 10.72 Directors' Supplemental Deferred Compensation Plan dated November 4, 1985. (Exhibit 10-188, 1988 Form 10-K, File No. 1-8222)
A 10.73 Management Incentive Compensation Plan as adopted September 9, 1985. (Exhibit 10-189, 1988 Form 10-K, File No. 1-8222)
A 10.73.1 Revised Management Incentive Plan as adopted February 5, 1990. (Exhibit 10-200, 1989 Form 10-K, File No. 1-8222)
A 10.74 Officers' Change of Control Agreements as approved October 3, 1988. (Exhibit 10-190, 1988 Form 10-K, File No. 1-8222)
A 10.78 Stock Option Plan for Non-Employee Directors dated April 30, 1993 (Exhibit 10.78, 1993 Form 10-K, File No. 1-8222)
A 10.79 Officers Insurance Plan dated November 15, 1993 (Exhibit 10.79, 1993 Form 10-K, File No. 1-8222)
A 10.80 Directors'Supplemental Deferred Compensation Plan dated (Exhibit 10.80, 1993 Form 10-K, File No. 1-8222)
A 10.81 Officers' Supplemental Deferred Compensation Plan dated (Exhibit 10.81, 1993 Form 10-K, File No. 1-8222)
A - Compensation related plan, contract, or arrangement.
16. Change in certifying accountant (July 1, 1985 Form 8-K, File No. 1-8222)
18. Letter re change in accounting principles (1980 3rd Quarter Form 10-Q, File No. 1-8222)
21. Subsidiaries of the Registrant
* 21.1 List of Subsidiaries of Registrant
23. Consents of Experts and Counsel
* 23.1 Consent of Independent Public Accountants
27. Financial Data Schedule
(b) Reports on Form 8-K:
The Company filed the following reports on Form 8-K during the quarter ended December 31, 1994:
1. Item 5. Other Events, dated October 31, 1994 re: Retail Rate Order.
2. Item 5. Other Events, dated November 9, 1994 re: Third quarter 1994 report to shareholders and a press release reporting a new corporate strategy.
Item 7. Financial Statements, Pro Forma Financial Information and Exhibits. Exhibit Number 13, Letter to Shareholders. Exhibit Number 20, Press Release.
3. Item 5. Other Events, dated December 30, 1994 re: Legal proceeding.
Report of Independent Public Accountants To the Board of Directors of Central Vermont Public Service Corporation:
We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements included in Central Vermont Public Service Corporation's annual report to shareholders, included in this Form 10-K, and have issued our report thereon dated February 6, 1995. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed in the index above is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly state, in all material respects, the consolidated financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Boston, Massachusetts February 6, 1995
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CENTRAL VERMONT PUBLIC SERVICE CORPORATION
By /s/ Thomas C. Webb -------------------------------------- Thomas C. Webb, President and Chief Executive Officer
By /s/ Robert H. Young -------------------------------------- Robert H. Young, Executive Vice President - Chief Operating Officer
By /s/ Frederick S. Potter -------------------------------------- Frederick S. Potter, Vice President - Finance and Administration and Principal Financial Officer
By /s/ James M. Pennington -------------------------------------- James M. Pennington, Controller and Principal Accounting Officer
March 13, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
March 13, 1995 /s/ Frederic H. Bertrand ----------------------------------------- Frederic H. Bertrand Director
March 13, 1995 /s/ Robert P. Bliss, Jr. ----------------------------------------- Robert P. Bliss, Jr. Director
March 13, 1995 /s/ Elizabeth Coleman ----------------------------------------- Elizabeth Coleman Director
March 13, 1995 /s/ ----------------------------------------- Luther F. Hackett Director
March 13, 1995 /s/ F. Ray Keyser, Jr. ----------------------------------------- F. Ray Keyser, Jr. Director
March 13, 1995 /s/ Mary Alice McKenzie ----------------------------------------- Mary Alice McKenzie Director
March 13, 1995 /s/ Gordon P. Mills ----------------------------------------- Gordon P. Mills Director
March 13, 1995 /s/ Preston Leete Smith ----------------------------------------- Preston Leete Smith Director
March 13, 1995 /s/ Robert D. Stout ----------------------------------------- Robert D. Stout Director
March 13, 1995 /s/ Thomas C. Webb ----------------------------------------- Thomas C. Webb Director