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

ITEM 1. BUSINESS
THE COMPANY
Green Mountain Power Corporation (the "Company") is a public utility operating company engaged in supplying electrical energy in the State of Vermont in a territory with an estimated population of 195,000. It serves approximately 79,500 customers. For the year ended December 31, 1993, the Company's sources of revenue were derived as follows: 33.2% from residential and lease customers, 31.6% from small commercial and industrial customers, 21.1% from large commercial and industrial customers, 9.6% from sales to other utilities, and 4.5% from other sources. For the same period, the Company's energy resources for retail and requirements wholesale sales were obtained as follows: 42.5% from hydroelectric sources (6.6% Company-owned, 1.6% New York Power Authority ("NYPA"), 28.6% Hydro- Quebec and 5.7% small power producers), 28.5% from nuclear generating sources (the Vermont Yankee plant described below), 14.8% from coal sources, 1.1% from natural gas, 0.7% from oil and 0.4% from wood. The remaining 12.0% was purchased on a short-term basis from other utilities and through the New England Power Pool ("NEPOOL"). In 1993, the Company purchased 91.8% of the energy required to satisfy its retail and requirements wholesale sales (including energy purchased from Vermont Yankee and under other long-term purchase arrangements). See Note K of Notes to Consolidated Financial Statements.
A major source of the Company's power supply is its entitlement to a share of the power generated by the 520-MW Vermont Yankee nuclear generating plant owned and operated by Vermont Yankee Nuclear Power Corporation ("Vermont Yankee"), in which the Company has a 17.9% equity interest. For information concerning Vermont Yankee, see "Power Resources - - Vermont Yankee."
The Company participates in NEPOOL, a regional bulk power transmission organization established to assure the reliability and economic efficiency of power supply in the Northeast. The Company's representative to NEPOOL is the Vermont Electric Power Company, Inc. ("VELCO"), a transmission consortium owned by the Company and other Vermont utilities, in which the Company has a 30% equity interest. As a member of NEPOOL, the Company benefits from increased efficiencies of centralized economic dispatch, availability of replacement power for scheduled and unscheduled outages of its own power sources, sharing of bulk transmission facilities and reduced generation reserve requirements.
The principal territory served by the Company comprises an area roughly 25 miles in width extending 90 miles across north central Vermont between Lake Champlain on the west and the Connecticut River on the east. Included in this territory are the cities of Montpelier, Barre, South Burlington, Vergennes and Winooski, as well as the Village of Essex Junction and a number of smaller towns and communities. The Company also distributes electricity in four noncontiguous areas located in southern and southeastern Vermont that are interconnected with the Company's principal service area
Note: Included in the energy sales and operating statistics described in this Annual Report on Form 10-K are NYPA lease transmissions. For information concerning NYPA lease transmissions, see "Power Resources - New York Power Authority."
through the transmission lines of VELCO and others. Included in these areas are the communities of Vernon (where the Vermont Yankee plant is located), Bellows Falls, White River Junction, Wilder, Wilmington and Dover. During 1993, the Company also supplied six firm wholesale customers, including four municipal and two cooperative utilities in Vermont and two utilities in other states. The Company is obligated to meet the changing electrical requirements of these wholesale customers, in contrast to the Company's obligation to other wholesale customers, which is limited to specified amounts of capacity and energy established by contract.
Major business activities in the Company's service areas include computer assembly and components manufacturing (and other electronics manufacturing), granite fabrication, service enterprises such as government, insurance and tourism (particularly winter recreation), and dairy and general farming.
During the years ended December 31, 1993, 1992 and 1991, electric energy sales to International Business Machines Corporation ("IBM"), the Company's largest customer, accounted for 13.6%, 13.8% and 13.0%, respectively, of the Company's operating revenues in those years. No other retail customer accounted for more than one percent of the Company's revenue.
RECENT RATE DEVELOPMENTS
On October 1, 1993, the Company filed a request with the Vermont Public Service Board ("VPSB") to increase retail rates by 8.6%. The increase is needed primarily to cover the cost of buying power from independent power producers, the cost of energy conservation programs, the cost of plant additions made in the past two years, and costs incurred in 1992 and 1993 associated with the Company's response to the Environmental Protection Agency's ("EPA") Remedial Investigation/Feasibility Study ("RI/FS") and proposed remedy at the Pine Street Marsh site and with the Company's litigation against its previous insurers seeking recovery of past costs incurred and indemnity against future liabilities in connection with the site. On January 28, 1994, the Company and the other parties in the proceeding reached a settlement agreement providing for a 2.9% retail rate increase effective June 15, 1994, and a target return on equity for utility operations of 10.5%. The settlement agreement also provided for the Company's recovery in rates of $4,200,000 in costs associated with the Pine Street Marsh site. The agreement must be reviewed and approved by the VPSB before it can take effect.
CONSTRUCTION
The Company's capital requirements result from the need to construct facilities or to invest in programs to meet anticipated customer demand for electric service. The policy of the Company is to increase diversification of its power supply and other resources through various means, including power purchase and sales arrangements, and relying on sources that represent relatively small additions to the Company's mix to satisfy customer requirements. This permits the Company to meet its financing needs in a flexible, orderly manner. Planned expenditures for the next five years will be primarily for transmission, distribution and conservation projects.
Capital expenditures over the past three years and forecasted for the next five years are as follows:
Construction projections are subject to continuing review and may be revised from time-to-time in accordance with changes in the Company's financial condition, load forecasts, the availability and cost of labor and materials, licensing and other regulatory requirements, changing environmental standards and other relevant factors.
For the period 1991-1993, internally generated funds, after payment of dividends, provided approximately 47% of total capital requirements for construction, sinking fund obligations and other requirements, including working capital. Internally generated funds provided 46% of such requirements for 1993. It is expected that funds so generated will provide approximately 67% of such requirements for the period 1994 through 1998, with the remainder to be derived through short-term borrowings and the issuance of senior securities and common stock.
In November 1993, the Company sold $20 million of its first mortgage bonds in two components: $15 million that will mature in 2018 and $5 million that will mature in 2000. The 2018 and 2000 bonds will bear interest at the rates of 6.7% and 5.71%, respectively. The proceeds from the sale of such bonds were used to refinance existing debt, to finance construction and conservation expenditures, and for other corporate purposes.
The Company anticipates issuing additional shares of its common stock in 1994. The amount and timing of such issuance will depend upon the financial condition of the Company, prevailing market conditions and other relevant factors.
In connection with the foregoing, see Management's Financial Analysis in Item 7 herein and the material appearing under the caption "Power Resources."
OPERATING STATISTICS For the Years Ended December 31
(1) See Note K of Notes to Consolidated Financial Statements. (2) Load factor is based on net system peak and firm MWH production less off-system losses.
DEMAND-SIDE MANAGEMENT
The Company has committed itself to the development and implementation of demand-side management programs as part of its long-term resource strategy. These programs are aimed at improving the match between customer needs and the Company's ability to supply those needs at a reasonable cost. Energy conservation, load management and efficient electric use are central to these program efforts and provide the means for controlling operating expenses and requirements for additional capital investment. With more efficient electric consumption, the use of existing resources can be optimized. Demand-side management program components, energy conservation, load-management and efficient electric use also provide customers with options and choices with respect to their use and cost of electric service.
Due to the economics of New England's current excess power supply market, the Company is expected to reevaluate demand-side management program design in 1994 to take into account lower marginal avoided costs. This program redesign may entail program modifications, curtailment or deferment, the addition of strategies for strategic efficient load growth, and modification of existing energy conservation measures.
Integrated Resource Plan. In 1990, the Company entered into a collaborative design agreement with the Vermont Department of Public Service, the Conservation Law Foundation and other interested parties to assist with the development of its demand-side management plans. This collaborative design process culminated with an agreement on the design of eleven specific demand-side management programs and on issues related to regulatory approval and cost recovery for program implementation. These demand-side management programs were filed with the VPSB in May 1991. The VPSB approved these programs in September 1991.
In October 1991, the Company completed development of its second formal Integrated Resource Plan. The Plan identified the most cost- effective composite of supply- and demand-side resource alternatives to meet the anticipated future energy needs of the Company's customers; integrated the planning functions of the energy supply, demand-side management, finance and engineering areas of the Company; and incorporated the implementation of those specific demand-side management programs approved by the VPSB in 1991. The Plan forecasted an increasing role for demand-side management in future Company operations. Planned demand-side management programs are projected to meet approximately one-third of the Company's expected load growth into the next century.
Current engineering and economic assumptions vary from those used in the Company's October 1991 Integrated Resource Plan. Avoided power supply costs have declined considerably. As a consequence, it is likely that the pace of demand-side management expenditures could change.
Rate Design. The Company seeks to design rates to encourage the shifting of electrical use from peak hours. Since 1976, the Company has offered optional time-of-use rates for residential and commercial customers. Currently, approximately 3,000 of the Company's residential customers continue to be billed on the original 1976 time-of-use rate basis. In 1987, the Company received regulatory approval for a new rate design that permits it to charge prices for electric service that reflect as accurately as possible the cost burden imposed by each customer class. The Company depends on fair pricing to keep customers satisfied and to make predictable the customer use of its power supply so that it can keep control of its costs. This rate structure helps to achieve these goals. Since inefficient use of electricity increases its cost, customers who are charged prices that reflect the cost of providing electrical service have real incentives to follow the most efficient usage patterns. Included in the VPSB's order approving this rate design was a requirement that the Company's 4,000 largest customers be charged time-of-use rates on a phased- in basis by 1994. As of April 1, 1991, approximately 1,300 of the Company's largest customers, comprising 48% of retail revenues, were successfully converted to time-of-use rates. During 1991 additional implementation of time-of-use rates was discontinued until further research on the cost effectiveness of time-of-use rates for small customers is performed. This work is continuing and will be reflected in the Company's next rate design proceeding, expected to be filed during the second quarter of 1994.
Dispatchable and Interruptible Service Contracts. In 1993, the Company had dispatchable and interruptible power contracts with four major ski areas, interruptible only contracts with three other customers and dispatchable-only contracts with four customers. The dispatchable portions of the contracts allow customers to purchase additional energy when the Company has low-cost electricity available ("dispatchable hours"), while the interruptible portions of the contracts allow the Company to avoid power supply capacity charges by reducing the Company's capacity requirements. Due to the surplus capacity in the region, the Company suspended the interruptible portions of the contracts but continued to offer the dispatchable portions to its customers.
In 1993, the Company revised its tariffs to permit other commercial customers to participate in the dispatchable and interruptable service contract program if their load requirements made it practical for them to do so. As of the end of 1993, three additional customers had signed contracts to participate in the program. By participating in the program these customers can now buy electricity from the Company during dispatchable hours without incurring a demand charge. The Company, in turn, is able to retain customer load requirements that otherwise might have been met through self-generation.
Ripple Load-Management System. The Company has operated a remote- control load-management facility since 1976. This facility, referred to as a "Ripple" system, allows the Company, from a central signaling point, to switch off temporarily certain electrical appliances in customers' homes that have a storage capacity, such as water heaters and thermal storage heaters, thereby eliminating electric loads at discreet times. The Company's present Ripple system consists of 7,100 installed signal receivers, a central processing station and four signal injection stations. Approximately 25% of the Company's eligible customers are participating in this load-control program, which allows the Company to reduce system load by four to five MW.
Commercial/Industrial Energy Management Services. In 1993, the Company offered five commercial and industrial energy efficiency programs to qualifying customers. These programs offer comprehensive technical assistance to identify cost-effective electric energy efficiency opportunities which may qualify for financial incentives. In addition, fuel-switching opportunities are identified for customers, although no direct financial incentives are provided. Approximately 1,000 customers participated in these programs in 1993, resulting in an approximate savings of 16,000 MWh. In 1993, the Company achieved approximately 160% of its energy savings targets developed in the collaborative design agreement discussed above, with the overall program performance (residential, commercial and industrial) of approximately 145% of the energy savings targets.
Residential Energy Management Services. In 1993, the Company offered six demand-side management programs to serve residential customers. The VPSB had approved these programs in 1991. These programs offer a variety of services to assist customers to identify and implement appropriate electric energy strategies or fuel-switching opportunities for their residences. In the case of electric efficiency improvements, the Company will also offer various financial incentives for the installation of such measures. Approximately 6,000 residential customers participated in these programs in 1993 resulting in an annual savings of approximately 3,419 MWh.
POWER RESOURCES
The Company generated, purchased and (in the case of NYPA power) transmitted 1,848,608 MWh of energy for retail and requirements wholesale customers for the twelve months ended December 31, 1993. The corresponding maximum one-hour integrated demand during that period was 307.3 MW on February 1, 1993. This compares to the previous all-time peak of 322.6 MW on December 27, 1989. The following tabulation shows the annual average capacity, the source of such energy for the twelve-month period and the capacity in the month of the period system peak. See also "Power Resources - - Long-Term Power Sales."
NOTE: (a) Excludes losses on off-system purchases, totaling 37,357 MWh. (b) Average annual capability associated with the Vermont Yankee source is adjusted to reflect system sale obligations. See "Power Resources -- Long-Term Power Sales."
Vermont Yankee. The Company and Central Vermont Public Service Corporation acted as lead sponsors in the construction of the Vermont Yankee nuclear plant, a boiling-water reactor designed by General Electric Company. The plant, which became operational in 1972, has a generating capacity of 520 MW. Vermont Yankee has entered into power contracts with its sponsor utilities, including the Company, that expire at the end of the life of the unit. Pursuant to its Power Contract, the Company is required to pay 20% of Vermont Yankee's operating expenses (including depreciation and taxes), fuel costs (including charges in respect of estimated costs of disposal of spent nuclear fuel), decommissioning expenses, interest expense and return on common equity, whether or not the Vermont Yankee plant is operating. In 1969, the Company sold to other Vermont utilities 2.735% of its entitlement to the output of Vermont Yankee. Accordingly, those utilities have an obligation to the Company to pay 2.735% of Vermont Yankee's operating expenses, fuel costs, decommissioning expenses, interest expense and return on common equity. Vermont Yankee has also entered into capital funds agreements with its sponsor utilities that expire on December 31, 2002. Under its Capital Funds Agreement, the Company is required, subject to obtaining necessary regulatory approvals, to provide 20% of the capital requirements of Vermont Yankee not obtained from outside sources. See Notes 1 and 2 of Notes to Financial Statements of Vermont Yankee.
On April 27, 1989, Vermont Yankee applied to the Nuclear Regulatory Commission ("NRC") for an amendment to its operating license to extend the expiration date from December 2007 to March 2012, in order to take advantage of current NRC policy to issue operating licenses for a 40-year term measured from the grant of the operating license. (Prior NRC policy, under which the operating license was issued, called for a term of 40 years from the date of the construction permit.) On August 22, 1989, the State of Vermont, opposing the license extension, filed a request for a hearing and petition for leave to intervene, which petition was subsequently granted. On December 17, 1990, the NRC issued an amendment to the operating license extending the expiration date until March 21, 2012, based upon a "no significant hazards" finding by the NRC Staff and subject to the outcome of the evidentiary hearing on the State of Vermont's assertions. On July 31, 1991, Vermont Yankee reached a settlement with the State of Vermont, and the State filed a withdrawal of its intervention. The proceeding was dismissed on September 3, 1991.
During periods when Vermont Yankee is unavailable, the Company incurs replacement-power costs in excess of those costs that the Company would have incurred for power purchased from Vermont Yankee. Replacement power is available to the Company from NEPOOL and through special contractual arrangements with other utilities. Replacement-power costs adversely affect cash flow and, absent deferral, amortization and recovery through rates, would adversely affect reported earnings. Routinely, in the case of scheduled outages for refueling, the VPSB has permitted the Company to defer, amortize and recover these excess replacement power costs for financial reporting and ratemaking purposes over the period until the next scheduled outage. Vermont Yankee has adopted an 18-month refueling schedule. In late August 1993, Vermont Yankee began a scheduled refueling outage which was completed on October 26, 1993. Vermont Yankee's next scheduled refueling is March 1995. In the case of unscheduled outages of significant duration resulting in substantial unanticipated costs for replacement power, the VPSB generally has authorized deferral, amortization and recovery of such costs.
Vermont Yankee incurred capital expenditures of approximately $7,229,000 in 1993, $10,750,000 in 1992 and $6,596,000 in 1991. Vermont Yankee estimates capital expenditures amounting to approximately $15,650,000 for 1994.
During the year ended December 31, 1993, the Company utilized 531,997 MWh of Vermont Yankee energy to meet 28.6% of its retail and requirements wholesale sales. The average cost of electricity produced by the plant in 1993 was 5.3 cents per KWh. In 1993, Vermont Yankee had an annual capacity factor of 76.9%, compared to 83.3% in 1992 and 91.2% in 1991.
The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $9,400,000,000. Any liability beyond $9,400,000,000 is indemnified under an agreement with the NRC. The first $200,000,000 of liability coverage is the maximum provided by private insurance. The Secondary Financial Protection program is a retrospective insurance plan providing additional coverage up to $9,200,000,000 per incident by assessing retrospective premiums of $79,300,000 against each of the 116 reactor units in the United States that are currently subject to the Program, limited to a maximum assessment of $10,000,000 per incident per nuclear unit in any one year. The maximum assessment is to be adjusted at least every five years to reflect inflationary changes.
The above insurance covers all workers employed at nuclear facilities prior to January 1, 1988, for bodily injury claims. Vermont Yankee has purchased a master worker insurance policy with limits of $200,000,000 with one automatic reinstatement of policy limits to cover workers employed on or after January 1, 1988. Vermont Yankee's estimated contingent liability for a retrospective premium on the master worker policy as of December 1993 is $3,100,000. The secondary financial protection program referenced above provides coverage in excess of the Master Worker policy.
Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL II) to cover the costs of property damage, decontamination or premature decommissioning resulting from a nuclear incident. All companies insured with NEIL II are subject to retroactive assessments if losses exceed the accumulated funds available to NEIL II. The maximum potential assessment against Vermont Yankee with respect to losses arising during the current policy year is $5,800,000 at the time of the first loss and $12,300,000 at the time of a subsequent loss. Vermont Yankee's liability for the retrospective premium adjustment for any policy year ceases six years after the end of that policy year unless prior demand has been made.
HYDRO-QUEBEC:
Highgate Interconnection. On September 23, 1985, the Highgate transmission facilities, which were constructed to import energy from Hydro-Quebec in Canada, began commercial operation. The transmission facilities at Highgate include a 200-MW AC-to-DC-to-AC converter terminal and seven miles of 345-kV transmission line. VELCO built and operates the converter facilities, which are jointly owned by a number of Vermont utilities, including the Company.
NEPOOL/Hydro-Quebec Interconnection. VELCO and certain other NEPOOL members have entered into agreements with Hydro-Quebec providing for the construction in two phases of a direct interconnection between the electric systems in New England and the electric system of Hydro-Quebec in Canada. The Vermont participants in this project, which has a capacity of 2,000 MW, will derive about 9% of the total power-supply benefits associated with the NEPOOL/Hydro-Quebec interconnection. The Company, in turn, receives about one-third of the Vermont share of those benefits.
The benefits of the interconnection include access to surplus hydroelectric energy from Hydro-Quebec at a cost below that of the replacement cost of power and energy otherwise available to the New England participants; energy banking, under which participating New England utilities will transmit relatively inexpensive energy to Hydro-Quebec during off-peak periods and will receive equal amounts of energy, after adjustment for transmission losses, from Hydro-Quebec during peak periods when replacement costs are higher; and provision for emergency transfers and mutual backup to improve reliability for both the Hydro-Quebec system and the New England systems.
Phase I. The first phase ("Phase I") of the NEPOOL/Hydro-Quebec Interconnection consists of transmission facilities having a capacity of 690 MW that traverse a portion of eastern Vermont and extend to a converter terminal located in Comerford, New Hampshire. These facilities entered commercial operation on October 1, 1986. Vermont Electric Transmission Company, Inc. ("VETCO"), a wholly owned subsidiary of VELCO, was organized to construct, own and operate those portions of the transmission facilities located in Vermont. Total construction costs incurred by VETCO for Phase I were $47,850,000. Of that amount, VELCO provided $10,000,000 of equity capital to VETCO through sales of VELCO preferred stock to the Vermont participants in the Project. The Company purchased $3,100,000 of VELCO preferred stock to finance the equity portion of Phase I. The remaining $37,850,000 of construction cost was financed by VETCO's issuance of $37,000,000 of long-term debt in the fourth quarter of 1986 and the balance of $850,000 was financed by short-term debt.
Under the Phase I contracts, each New England participant, including the Company, is required to pay monthly its proportionate share of VETCO's total cost of service, including its capital costs, as well as a proportionate share of the total costs of service associated with those portions of the transmission facilities to be constructed in New Hampshire by a subsidiary of New England Electric System.
Phase II. Agreements executed in 1985 among the Company, VELCO and other NEPOOL members and Hydro-Quebec, provided for the construction of the second phase ("Phase II") of the interconnection between the New England electric system and that of Hydro-Quebec. Phase II expands the Phase I facilities from 690 MW to 2,000 MW, and provides for transmission of Hydro- Quebec power from the Phase I terminal in northern New Hampshire to Sandy Pond, Massachusetts. Construction of Phase II commenced in 1988 and was completed in late 1990. The Phase II facilities commenced commercial operation November 1, 1990, initially at a rating of 1,200 MW, and increased to a transfer capability of 2,000 MW in July 1991. The Hydro- Quebec-NEPOOL Firm Energy Contract provides for the import of economical Hydro-Quebec energy into New England. The Company is entitled to 3.2% of the Phase II power-supply benefits. Total construction costs for Phase II were approximately $487,000,000. The New England participants, including the Company, have contracted to pay monthly their proportionate share of the total cost of constructing, owning and operating the Phase II facilities, including capital costs, for 30 years. The agreements providing for the operation and support of the Phase II facilities meet the capital lease accounting requirements under SFAS 13. At December 31, 1993, the present value of the Company's obligation was $11,000,000. The Company's projected future minimum payments under the Phase II support agreements are $501,311 for each of the years 1994-1998 and an aggregate of $8,522,270 for the years 1999-2020.
The Phase II portion of the project is owned by New England Hydro- Transmission Electric Company, Inc. and New England Hydro-Transmission Corporation, subsidiaries of New England Electric System, in which certain of the Phase II participating utilities, including the Company, own equity interests.
The Company owns approximately 3.2% of the equity of the corporations owning the Phase II facilities. During construction of the Phase II project, the Company, as an equity sponsor, was required to provide equity capital. At December 31, 1993, the capital structure of such corporations was 40% common equity and 60% long-term debt.
Hydro-Quebec Power Supply Contracts. Under various contracts approved by the VPSB, the details of which are described in the table below, the Company purchases capacity and associated energy produced by the Hydro- Quebec system. Such contracts obligate the Company to pay certain fixed capacity costs whether or not energy purchases above a minimum level set forth in the contracts are made. Such minimum energy purchases must be made whether or not other, less expensive energy sources might be available. These contracts are intended to complement the other components in the Company's power supply to achieve the most economic power-supply mix reasonably available.
* Estimated average ** Estimated average in nominal dollars, levelized over the period indicated.
On October 12, 1990, the VPSB granted conditional approval of the Company's purchases pursuant to the contract with Hydro-Quebec entered into December 4, 1987: (1) Schedule A -- 17 MW of firm capacity and associated energy to be delivered at the Highgate interconnection for five years beginning 1990; (2) Schedule B -- 68 MW of firm capacity and associated energy to be delivered at the Highgate interconnection for twenty years beginning in September 1995; and (3) Schedule C3 -- 46 MW of firm capacity and associated energy to be delivered at interconnections to be determined at a later time for 20 years beginning in November 1995. The opponents to the December 1987 contract (principally the Crees, native peoples living in northern Quebec) appealed the VPSB's October 1990 order to the Vermont Supreme Court. On October 2, 1992, the Vermont Supreme Court affirmed the VPSB's October 1990 order. On February 12, 1992, the VPSB issued an order finding that the Company had complied with substantial conditions imposed by the VPSB in its October 1990 order and approved the Company's purchase under the December 1987 contract. In March 1992, the opponents to the December 1987 contract appealed the VPSB'S February 1992 compliance order to the Vermont Supreme Court. On May 7, 1993, the Vermont Supreme Court affirmed the VPSB's compliance order approving the Company's purchases under the December 1987 contract.
The Company anticipates that the Schedule C3 purchases will be delivered over its entitlement to the NEPOOL/Hydro-Quebec interconnection (Phase I and Phase II). If such interconnection is utilized, the Company must forego certain savings associated with other energy deliveries and capacity arrangements that would benefit the Company if the interconnection were not utilized for delivery of the Schedule C3 purchases. The Company believes that the benefits of the Schedule C3 purchases, if power is delivered over such interconnection, will offset the value of the foregone savings.
In September 1993, the Company negotiated a renewal of a short-term "tertiary energy" contract with Hydro-Quebec under which Hydro-Quebec delivers 61 MW of capacity and energy to the Company over the NEPOOL/Hydro- Quebec interconnection. The electricity purchased under this tertiary contract is priced at less than 2.5 cents per KWh. The benefits realized by the Company from this favorably priced electricity will be greater than those associated with deliveries foregone by the Company otherwise available over the NEPOOL/Hydro-Quebec interconnection. This tertiary energy contract will expire in August 1994. The Company anticipates that purchases of tertiary energy will extend beyond August 1994, but will end when the Schedule C3 deliveries begin in November 1995.
On September 27, 1990, the Canadian National Energy Board ("NEB") issued its decision approving the export by Hydro-Quebec pursuant to the December 1987 contract. The NEB, however, imposed a condition on its approval: Hydro-Quebec's export license was to be deemed valid so long as Hydro-Quebec obtained all federal and environmental approvals required for any of its new hydroelectric generating units advanced in order to satisfy Hydro-Quebec's contractual obligations. Hydro-Quebec and the Province of Quebec appealed the imposition of this condition to the Federal Court of Appeal. In a decision handed down on July 9, 1991, the Federal Court of Appeal agreed with Hydro-Quebec's assertion that the NEB has no authority to regulate the construction of hydroelectric generating units -- a matter that lies exclusively within provincial jurisdiction under the Canadian Constitution. The Federal Court of Appeal struck down the challenged NEB license condition and otherwise affirmed the license. The opponents to the December 1987 contract appealed the decision of the Federal Court of Appeal to the Supreme Court of Canada. On February 24, 1994, the Supreme Court of Canada rendered a decision reversing the judgment of the Federal Court of Appeal, and reinstated the NEB decision, including the condition that Hydro-Quebec had objected to.
The December 1987 contract, like the July 1984 contract, calls for the delivery of system power and is not related to any particular facilities in the Hydro-Quebec system. Consequently, there are no identifiable debt- service charges associated with any particular Hydro-Quebec facility that can be distinguished from the overall charges paid under the contract.
The December 1987 contract also contains a provision that prohibits Hydro-Quebec, for a period ending in 1995, from selling power under similar terms and conditions to any other United States utility at a price lower than the Company would pay unless the lower price is made available to the Company. The price of the energy acquired under the December 1987 contract will reflect adjustments in the United States Gross National Product Implicit Price Deflator over the term of the contract. The price of the capacity acquired will reflect adjustments in a pertinent construction cost index (the Handy Whitman Index of Public Utility Construction Costs) until the time deliveries begin. From the commencement of deliveries to the expiration of the contract, the capacity price is essentially frozen. (Some adjustments are made to reflect changes in financing costs over time.) Based on current integrated resource analyses, the Company believes that these contracts for Hydro-Quebec system power compare favorably with alternative long-term resources available to the Company.
In 1993, the Company utilized 353,729 MWh of Hydro-Quebec energy under the July 1984 contract, 67,833 MWh under the December 1987 contract Schedule A and 110,890 MWh under the tertiary energy contract to meet 28.6% of its retail and requirements wholesale sales. The average cost of Hydro- Quebec electricity in 1993 was 3.4 cents per KWh. See Notes J and K-2 of Notes to Consolidated Financial Statements.
New York Power Authority ("NYPA"). NYPA power provided 15,425 MWh to the Vermont Department of Public Service (the "Department") customers, delivered over the Company's facilities at an average retail rate of 0.9 cents per KWh. As of August 1993, the Department chose not to continue retailing NYPA power to the Company's customers. The Department now wholesales the allocation of NYPA power to the Company who, in turn, delivers the power to residential and farm customers. In addition, the Company purchased at wholesale 13,622 MWh of NYPA power at an average cost of 1.3 cents per KWh in 1993. Under the allocation currently made by NYPA of NYPA power to states neighboring New York, the amount of such power delivered to residential and farm customers in the Company's service territory will be as follows:
Entitlements to Customers in the Company's Period Service Territory (MW) ------ -------------------------
July 1993 - June 1994 2.0 July 1994 - June 1995 0.3 July 1995 - June 1996 0.3 July 1996 - June 1997 0.3
Merrimack Unit #2. Merrimack Unit #2 is a coal-fired steam plant of 356-MW capacity located in Bow, New Hampshire, and owned by Northeast Utilities. The Company is entitled to 30.457 MW of capacity and related energy from the unit under a 30-year contract terminating May 1, 1998. During the year ended December 31, 1993, the Company utilized 230,812 MWh from the unit to meet 12.4% of its total retail and requirements wholesale sales. Merrimack Unit #2 operated at a 73.1% annual capacity factor in 1993 and 66.8% in 1992. The average cost of electricity from this unit was 3.0 cents per KWh in 1993. See Note K-1 of Notes to Consolidated Financial Statements.
Stony Brook I. The Massachusetts Municipal Wholesale Electric Company ("MMWEC") is principal owner and operator of a 343.0-MW combined-cycle intermediate generating station -- Stony Brook I -- located in Ludlow, Massachusetts, which commenced commercial operation in November 1981. The Company entered into a Joint Ownership Agreement with MMWEC dated as of October 1, 1977, whereby the Company acquired an 8.8% ownership share of the plant, entitling the Company to 30.2 MW of capacity. In addition to this entitlement, the Company has contracted for 13.8 MW of capacity for the life of the Stony Brook I plant, for which it will pay a proportionate share of MMWEC's share of the plant's fixed costs and variable operating expenses. The three units that comprise Stony Brook I are primarily oil- fired. Two of the units are also capable of burning natural gas. The natural gas system at the plant was modified in 1985 to allow two units to operate simultaneously on natural gas.
During 1993, the Company utilized 20,591 MWh from this plant to meet 1.1% of its retail and requirements wholesale sales at an average cost of 9.8 cents per KWh. See Note I-3 and K-1 of Notes to Consolidated Financial Statements.
Ontario Hydro. The State of Vermont executed a five-year contract with Ontario Hydro, commencing November 1, 1987, and expiring October 31, 1992, which provides for the purchase by the State of 73 MW of high- availability power. The contract has options for increasing the power purchased starting November 1 of 1988, 1989, 1990 and 1991, to a maximum of 88 MW, 98 MW, 108 MW and 112 MW, respectively. This contract can be extended for three additional five-year periods. The maximum option increases have been exercised. The Company receives a share of the Ontario Hydro power imported by the State. The Company's obligation under this contract terminated as of December 1993. The Company's average share of such power for 1993 was 20.3 MW, and 44,165 MWh of Ontario Hydro energy were utilized to meet 2.4% of its retail and requirements wholesale sales. The average cost of this power was 5.3 cents per KWh in 1993.
Wyman Unit #4. The W. F. Wyman Unit #4, which is located in Yarmouth, Maine, is an oil-fired steam plant with a capacity of 619 MW. The construction of this plant was sponsored by the Central Maine Power Company. The Company has a joint-ownership share of 1.1% (7.1 MW) in the Wyman #4 unit, which began commercial operation in December 1978.
During 1993, the Company utilized 6,474 MWh from this unit to meet 0.3% of its retail and requirements wholesale sales at an average cost of 5.3 cents per KWh. See Note I-3 of Notes to Consolidated Financial Statements.
McNeil Station. The J. C. McNeil station, which is located in Burlington, Vermont, is a wood chip and gas-fired steam plant with a capacity of 53.6 MW. The Company has an 11% or 5.9 MW interest in the J. C. McNeil plant, which began operation in June 1984. During 1993, the Company utilized 11,561 MWh from this unit to meet 0.5% of its retail and requirements wholesale sales at an average cost of 7.0 cents per KWh. In 1989, the plant added the capability to burn natural gas on an as- available/interruptible service basis. See Note I-3 of Notes to Consolidated Financial Statements.
New York Power Purchases:
Rochester Gas and Electric Corporation. In 1988, the Company entered into a ten-year contract with Rochester Gas and Electric Corporation ("RG&E") for the purchase of up to 50 MW of firm power and associated energy. This flexible contract allows the Company the discretion of purchasing from 0 MW to 50 MW on a weekly basis. The Company has no obligation to purchase power in any week. When the Company elects to schedule a purchase, however, it must take and pay for energy at a 75% load factor, or pay a penalty, in the week of the purchase. Although the Company has no fixed capacity payments, it must pay to reserve transmission from the Niagara Mohawk Power Corporation ("Niagara Mohawk") for the 50-MW maximum purchase. Both RG&E and the Company have the option to terminate the contract effective 1995.
Pursuant to an agreement with Connecticut Light and Power Corporation ("CL&P") and Bozrah Light and Power Company ("Bozrah") that was finalized in December 1992, the Company exercised the option to terminate the RG&E contract and the transmission contract with Niagara Mohawk that supports it effective October 31, 1995. The Company also agreed to offer RG&E power to CL&P for purchase on a weekly basis through the remaining term of the RG&E contract, and to terminate a contract under which the Company supplied all of the electrical requirements of Bozrah, a small electric utility operating in Gilman, Connecticut. In return, CL&P, which will replace the Company as the supplier of electricity to Bozrah, will assume responsibility for approximately 75% of the fixed costs of the transmission contract with Niagara Mohawk, and will provide the Company with up to 50 MW of system power, to be scheduled on a weekly basis, at a total price expected to be lower than that provided under the existing RG&E contract. In addition, CL&P has offered the Company an option, which may be exercised in yearly increments starting in July 1994, to purchase up to 50 additional MW of system power for the period July 1995 through December 2004.
The Company expects that the reductions in its purchased power and fixed transmission costs derived from this three-party agreement will more than offset the loss of revenues associated with the termination of its electricity sales contract with Bozrah. The arrangement was approved by FERC effective May 1, 1993. Estimated Charges Annual Transmission Reservations $300,000 Average Cost per kWh (1993)(1) 4.1 cents (1994-1995)
(1) No power purchases were made under the RG&E or CL&P contracts described above during 1993.
Small Power Production. The VPSB has adopted rules that implement for Vermont the purchase requirements established by federal law in the Public Utility Regulatory Policies Act ("PURPA") of 1978. Under the rules, small power producers have the option to sell their output to a central state purchasing agent under a variety of long- and short-term, firm and non-firm pricing schedules, each of which is based upon the projected Vermont composite system's power costs which would be required but for the purchases from small producers. The state purchasing agent assigns the energy so purchased, and the costs of purchase, to each Vermont retail electric utility based upon its pro rata share of total Vermont retail energy sales. Utilities may also contract directly with producers. The rules provide that all reasonable costs incurred by a utility under the rules will be included in the utilities' revenue requirements for ratemaking purposes.
Currently, the state purchasing agent, Vermont Power Exchange, Inc., is authorized to seek 150 MW of power from qualifying facilities under PURPA, of which the Company's current pro rata share would be 32.6% or 48.8 MW.
In 1993, the Company, through both its direct contracts and the Vermont Power Exchange, purchased 106,647 MWh of small power production to meet 5.7% of its retail and requirements wholesale sales at an average cost of 10.0 cents per KWh.
Short-Term Opportunity Purchases and Sales. The Company has made arrangements with several utilities in New England and New York whereby the Company may make purchases or sales of utility system power on short notice and generally for brief periods of time when it appears economic to do so. Opportunity purchases are arranged when it is possible to purchase power from another utility for less than it would cost the Company to generate the power with its own sources. Purchases also help the Company save on replacement-power costs during an outage of one of its base load sources. Opportunity sales are arranged when the Company has surplus energy available at a price that is economic to other regional utilities at any given time. The sales are arranged based on forecasted costs of supplying the incremental power necessary to serve the sale. The price is set so as to recover the forecasted fuel and capacity costs.
During 1993, the Company purchased 222,565 MWh, 11.9% of the Company's retail and requirements wholesale sales, at an average cost of 2.4 cents per KWh under such arrangements.
NEPOOL. As a participant of NEPOOL, through VELCO, the Company takes advantage of pool operations with central economic dispatch of participants' generating plants, pooling of transmission facilities and economy and emergency exchange of energy and capacity. The NEPOOL agreement also imposes obligations on the Company to maintain a generating capacity reserve as set by the Pool, but which is lower than the reserve which would be required if the Company were not a Pool participant.
Company Hydroelectric Power. The Company wholly owns and operates eight hydroelectric generating facilities, the largest of which has a generating output of 8.8 MW, located on river systems within its service area. In 1993, these plants provided 123,946 MWh of low-cost energy, meeting 6.6% of the Company's retail and requirements wholesale sales at an average cost of 0.9 cents per KWh. See "State and Federal Regulation."
VELCO. The Company, together with six other Vermont electric distribution utilities, owns VELCO. Since commencing operation in 1958, VELCO has transmitted power for its owners in Vermont, including power from NYPA and other power contracted for by Vermont utilities. VELCO also purchases bulk power for resale at cost to its owners, and as a member of NEPOOL, represents all Vermont electric utilities in pool arrangements and transactions. See Note B of Notes to Consolidated Financial Statements.
Long-Term Power Sales. The Company has entered into agreements for a unit sale of power to Fitchburg Gas and Electric Light Company of 10 MW of Vermont Yankee capacity and associated energy from September 1, 1990 through October 31, 1996.
In 1986, the Company entered into an agreement for the sale to UNITIL of 23 MW of capacity produced by the Stony Brook I combined-cycle plant for a 12-year period commencing October 1, 1986. The agreement provides for the recovery by the Company of all costs associated with the capacity and energy sold.
Fuel. During 1993, the Company's retail and requirements wholesale sales were provided by the following fuel sources: 42.5% from hydro (6.6% Company-owned, 1.6% NYPA, 28.6% Hydro-Quebec and 5.7% small power producers), 28.5% from nuclear, 14.8% from coal, 1.1% from natural gas, 0.7% from oil and 0.4% from wood. The remaining 12.0% was purchased on a short-term basis from other utilities and through NEPOOL.
Vermont Yankee has approximately $165 million of "requirements based" purchase contracts for nuclear fuel needs to meet substantially all of its power production requirements through 2002. Under these contracts, any disruption of operating activity would allow Vermont Yankee to cancel or postpone deliveries until actually needed.
Vermont Yankee has a contract with the United States Department of Energy ("DOE") for the permanent disposal of spent nuclear fuel. Under this contract, DOE will provide disposal services when a facility for spent nuclear fuel and other high level radioactive waste is available, which is required under current statutes to be prior to January 31, 1998. A facility is not yet available. Vermont Yankee also bills its sponsors, including the Company, a disposal fee, which is subject to annual DOE adjustment of $.001 per KWh of net generation. See Management's Financial Analysis in Item 7 herein, Note B of Notes to Consolidated Financial Statements and Note 8 to Vermont Yankee Notes to Financial Statements.
The Company does not maintain long-term contracts for the supply of oil for the oil-fired peaking unit generating stations wholly owned by it (80 MW). The Company did not experience difficulty in obtaining oil for its own units during 1993, and, while no assurance can be given, does not anticipate any such difficulty during 1994. None of the utilities from which the Company expects to purchase oil- or gas-fired capacity in 1994 has advised the Company of grounds for doubt about maintenance of secure sources of oil and gas during the year.
Coal for Merrimack #2 is presently being purchased by contract and on the spot market from northern West Virginia and southern Pennsylvania sources. The sponsor of Merrimack advises that, as of February 28, 1994, there was a 90-day supply of coal at the plant.
Wood for the McNeil plant is furnished to the Burlington Electric Department from a variety of sources under short-term contracts ranging from several weeks' to six months' duration. The McNeil plant used 103,814 tons of wood chips and mill residue and 257,393,000 cubic feet of gas in 1993. The McNeil plant is forecasting consumption of wood chips for 1994 to be 120,000 tons and gas consumption of 600,000,000 cubic feet. Burlington Electric Department advises that, as of February 26, 1994, there were 9,200 tons of wood chips in inventory for the McNeil plant.
The Stony Brook combined-cycle generating station is capable of burning either natural gas or oil in two of its turbines. Natural gas is supplied to the plant subject to its availability. During periods of extremely cold weather, the supplier reserves the right to discontinue deliveries to the plant in order to satisfy the demand of its residential customers. The Company assumes for planning and budgeting purposes that the plant will be supplied with gas during the months of April through November, and that it will run solely on oil during the months of December through March. The plant maintains an oil supply sufficient to meet approximately one-half of its annual needs.
STATE AND FEDERAL REGULATION
General. The Company is subject to the regulatory authority of the VPSB, which extends to retail rates, services, facilities, securities issues and various other matters. The separate Vermont Department of Public Service, created by statute in 1981, is responsible for development of energy supply plans for the State, purchases of power as an agent for the State and other general regulatory matters. The VPSB is principally responsible for quasi-judicial proceedings, such as rate proceedings. The Department, through a Director for Public Advocacy, is entitled to participate as a litigant in such proceedings and regularly does so.
Vermont law pertaining to rate proceedings of the Company provides that the rates as filed become final and effective seven months after suspension of the filed rates (which can occur within 45 days of filing) if the VPSB fails to act on the permanent rate request by that time. Once filed, a request for permanent rate relief may not be amended or supplemented except upon approval of the VPSB after hearing. The VPSB must consider an application for and, in appropriate circumstances, order temporary rate relief pending a decision. If the VPSB fails to act on an application for temporary rate relief within 30 days, or within 45 days after suspension of the permanent rate request, the temporary rates take effect. If temporary relief is ordered, revenues recovered are subject to refund.
The Company's rate tariffs are uniform throughout its service area.
The Company's wholesale rate on sales to eight wholesale customers is regulated by the FERC. Revenues from sales to these customers were approximately 2.4% of operating revenues for 1993.
Included within these customers is the Bozrah Light and Power Company, a private electric utility in Connecticut, with whom the Company had a contract to provide wholesale electric service on a full-requirements basis. Service to Bozrah began in March 1987 and terminated May 1, 1993. See "Power Resources - New York Purchases: Rochester Gas and Electric Corporation" for a discussion of the three-party agreement negotiated by the Company relating to the termination of full-requirements service to Bozrah.
Late in 1989, the Company began serving two new municipal utilities, Northfield and Hardwick, under its wholesale tariff. These customers increased electricity sales by approximately 46,000 MWh and peak requirements by approximately 9 MW. Revenues in 1993 from Northfield and Hardwick were $1,727,058. Service to Hardwick under the Company's wholesale tariff terminated on April 30, 1993.
The Company provides transmission service to ten customers within the State under rates regulated by the FERC; revenues for such services amounted to less than 1% of the Company's operating revenues for 1993.
By reason of its relationship with Vermont Yankee, VELCO and VETCO, the Company has filed an exemption statement under Section 3(a)(2) of the Public Utility Holding Company Act, thereby securing exemption from the provisions of such Act, except for Section 9(a)(2) thereof (which prohibits the acquisition of securities of certain other utility companies without approval of the Securities and Exchange Commission). The Securities and Exchange Commission has the power to institute proceedings to terminate such exemption for cause.
Licensing. Pursuant to the Federal Power Act, the FERC has granted licenses for the following hydro projects:
Project Issue Date Period - ------- ----------- ------
Bolton February 5, 1982 February 5, 1982 - February 4, 2022
Essex * January 21, 1969 May 1, 1965 - December 31, 1993
Vergennes June 29, 1979 June 1, 1949 - May 31, 1999
Waterbury July 20, 1954 September 1, 1951 - August 31, 2001
* The Company is in the process of relicensing this facility and anticipates the final FERC license to be issued by mid-1994. The facility is currently operating on an annual license.
Major project licenses provide that after an initial twenty-year period, a portion of the earnings of such project in excess of a specified rate of return is to be set aside in appropriated retained earnings in compliance with FERC Order #5, issued in 1978. Although the twenty-year periods expired in 1985, 1969 and 1971 in the cases of the Essex, the Vergennes and the Waterbury projects, the amounts appropriated are not material.
Department of Public Service Twenty-Year Power Plan. On October 15, 1988, the Department adopted an update of its twenty-year electrical power- supply plan (the "Plan") for the State of Vermont. The Plan includes an overview of statewide growth and development as they relate to future requirements for electrical energy; an assessment of available energy resources; and estimates of electrical energy demand. The Plan calls for exploring the potential reduction of electrical demand through conservation and load management.
The Company continues to implement its Integrated Resource Plan in a manner consistent with the Department's Plan. The 1991 Integrated Resource Plan calls for the continued design and delivery of conservation and load management programs, customer programs and education programs as well as measures concerning the efficient distribution of power to the end user.
ENVIRONMENTAL MATTERS
In recent years, public concern for the physical environment has brought about increased government regulation of the licensing and operation of electric generation, transmission and distribution facilities. The Company must meet various land, water, air and aesthetic requirements as administered by local, state and federal regulatory agencies. Subject to the results of developments discussed below concerning the Pine Street Marsh site in Burlington, Vermont, the Company believes that it is in substantial compliance with such requirements, and no material complaints concerning compliance by the Company with present environmental protection regulations are outstanding. Because the regulations and requirements under existing legislation have not been fully promulgated (and, when promulgated, are subject to revision), because permits and licenses when issued may be conditional or may be subject to renewal and because additional legislation may be adopted in the future, the Company cannot presently forecast the costs or other effects which environmental regulation may ultimately have upon its existing and proposed facilities and operations.
In 1982, the United States Environmental Protection Agency ("EPA") notified the Company that the EPA, pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 ("CERCLA"), was considering spending public funds to investigate and take corrective action involving claimed releases of allegedly hazardous substances at a site identified as the Pine Street Marsh in Burlington, Vermont. On part of this site was located a manufactured-gas facility owned and operated by a number of separate enterprises, including the Company, from the late 19th century to 1967. In its notice, the EPA stated that the Company may be a "potentially responsible party" ("PRP") under CERCLA from which reimbursement of costs of investigation and of corrective action may be sought. On February 23, 1988, the Company received a Special Notice letter from the EPA stating that the letter constituted a formal demand for reimbursement of costs, including interest thereon, that were incurred and were expected to be incurred in response to the environmental problems at the site.
On December 5, 1988, the EPA brought suit against the Company, New England Electric System, and Vermont Gas Systems, Inc. in the United States District Court for the District of Vermont seeking reimbursement for costs it incurred in conducting activities in 1985 to remove allegedly hazardous substances from the site, and requested a declaratory judgment that the Company and the other defendants are liable for all costs that have been incurred since the removal and that continue to be incurred in responding to claims of releases or threatened releases from the Maltex Pond Area -- the portion of the site where the removal action occurred. The complaint specifically alleged that the EPA expended at least $741,000 during the 1985 removal action and sought interest on this amount from the date the funds were expended and costs of litigation, including attorneys' fees. The Company entered a cross-claim against New England Electric System and third-party claims against UGI Corporation, Southern Union Corporation, the State of Vermont, and an individual property owner at the site for recovery of its response costs and for contribution. Fourth-party defendants subsequently were joined.
In July 1990, the Company and other parties signed a proposed Consent Decree settling the removal action litigation. All 14 settling defendants contributed to the aggregate settlement amount of $945,000. Individual contributions were treated as confidential under the proposed Consent Decree.
On December 26, 1990, upon the unopposed motion of the United States, the Consent Decree was entered by the Court.
During the summer and fall of 1989, the EPA conducted the initial phase of the Remedial Investigation ("RI") and commenced the Feasibility Study ("FS") relating to the site. In the fall of 1990 and in 1991, the EPA conducted a second phase of RI work and studied the treatability of soils and groundwater at the site. In the fall of 1991, the EPA responded favorably to a request from the Company and other PRPs to participate in informal discussions on the EPA's ongoing investigation and evaluation of the site, and invited the Company and other interested parties to share technical information and resources with the EPA that might assist it in evaluating remedial options. Thereafter, the Company and other PRPs held several meetings with the EPA to discuss technical issues and received copies of the EPA's Supplemental Remedial Investigation Final Report, and its Baseline Risk Assessment Final Report.
On November 6, 1992, the EPA released its final RI/FS and announced a proposed remedy with an estimated total cost of approximately $49,500,000, including 30 years' operation and maintenance costs with a net present value of approximately $26,400,000. The EPA's preferred remedy called for construction of a Containment/Disposal Facility ("CDF") over a portion of the site. The CDF would have consisted of subsurface vertical barriers and a low permeability cap, with collection trenches and a hydraulic control system to capture groundwater and prevent its migration outside of the CDF. Collected groundwater would have been treated and discharged or stored and disposed of off-site. The proposed remedy also would have required construction of new wetlands to replace those that would be destroyed by construction of the CDF, and a long-term monitoring program.
On May 15, 1993, the PRP group in which the Company participated submitted extensive comments to the EPA opposing the proposed remedy. In response to an earlier request from the EPA, the PRP group also submitted a detailed analysis of an alternative remedy anticipated to cost approximately $20,000,000. In early June, in response to overwhelming negative comment, the EPA withdrew its proposed remedy and announced that it would work with all interested parties in developing a new proposal. Since then, the EPA has established a coordinating council, with representatives of PRPs, environmental groups, and government agencies, and presided over by a neutral mediator. The council is charged with determining what additional studies may be appropriate for the site and may also eventually address additional response activities. The Company is represented on the council.
In early 1994, the Company and other PRPs met with the EPA to commence negotiations on an Administration Order of Consent pursuant to which the PRPs would conduct additional studies agreed to by the coordinating council. Although negotiations are not yet complete, it is likely that the EPA will consent to allowing the PRPs to conduct additional studies at the site and that the EPA will not require reimbursement for its past RI/FS study costs as a condition to allowing the PRPs to conduct these additional studies. The EPA has previously advised the Company that ultimately it will seek to hold the Company and the PRPs liable for such costs.
In September 1991, the Company, New England Electric System and Vermont Gas Systems, Inc. entered into confidential negotiations with most other PRPs concerning allocation of unresolved liabilities concerning the site. Those negotiations are continuing.
In December 1991, the Company brought suit against several previous insurers seeking recovery of unrecovered past costs and indemnity against future liabilities associated with environmental problems at the site. The parties to this action are engaged in discovery and motions practice.
The Company has reached a confidential settlement with one of the defendants that provided the Company with second layer excess liability coverage for a seven month period in 1976. The Company has also reached a confidential agreement in principle with another insurance company defendant that provided the Company with comprehensive general liability insurance between 1976 and 1982, and with environmental impairment liability insurance from 1981 to 1984. These policies were in place in 1982 when the EPA first notified the Company that it might be a potentially responsible party at the Pine Street Marsh site.
The Company is unable to predict at this time the magnitude of any liability resulting from potential claims for the costs of the RI/FS or the performance of any remedial action, or the likely disposition or magnitude of claims the Company may have against others, including its insurers, except to the extent described above.
In its 1991 rate case, the Company, for the first time, sought recovery for expenses associated with the Pine Street Marsh site. Specifically, the Company proposed rate recognition of its estimated, unrecovered 1991 expenditures (approximately $400,000) for technical consultants and legal assistance in connection with the EPA's enforcement actions at the site and insurance litigation. While reserving the right to argue in the future about the appropriateness of rate recovery for Pine Street Marsh related costs, the Company and the Department reached agreement that the full amount of Pine Street Marsh costs reflected in the Company's 1991 rate case should be recovered in rates. The Company's rates approved by the VPSB on April 2, 1992, reflected the 1991 Pine Street Marsh related expenditures referred to above.
In its rate increase request filed on October 1, 1993, the Company proposed rate recognition for its expenditures between January 1, 1992 and July 31, 1993 (approximately $4,200,000) for technical consultants and legal assistance in connection with the EPA's enforcement actions at the site and insurance litigation. The Department and the Company have reached the same agreement regarding recovery of these costs in rates that they reached with respect to the Company's 1991 Pine Street Marsh related expenditures. A comprehensive settlement of the Company's 1993 rate case, including the agreement regarding Pine Street Marsh costs, is currently pending before the VPSB.
As of December 31, 1993, the Company had reserved approximately $680,000 for costs attributable to the site, other than those costs that are the subject of the agreements between the Department and the Company mentioned above. Management expects to seek and receive ratemaking treatment for other costs incurred beyond the amounts that have been reserved. As of December 31, 1993, such other costs are approximately $4,918,000, which includes the $4,200,000 in costs that are the subject of the most recent rate case settlement agreement referred to above.
COMPETITION
The Company serves a fixed area of Vermont under VPSB franchise. Except as noted below, the Company's electric business is substantially free from competition from other electric utilities, municipalities and other public agencies in its franchise area, as mandated by the VPSB. The Company, however, competes with other providers of energy for the home- heating market. Wood stoves, oil-burning furnaces and natural gas represent the principal alternatives to electric heat for customers in the Company's service territory. Fluctuations in the price of fossil fuels, especially oil and natural gas, affect the Company's position in the home- heating market.
Legislative authority has existed since 1941 that would permit Vermont cities, towns and villages to own and operate public utilities. Since that time, no municipality served by the Company has established or, as far as is known to the Company, is presently taking steps to establish, a municipal public utility.
In 1987, the Vermont General Assembly enacted legislation that authorized the Department to sell electricity on a significantly expanded basis. Before the new law was passed, the Department's authority to make retail sales had been limited: It could sell at retail only to residential and farm customers and could sell only power that it had purchased from the Niagara and St. Lawrence projects operated by the New York Power Authority.
Under the new law, the Department can sell electricity purchased from any source at retail to all customer classes throughout the state, but only if it convinces the VPSB and other state officials that the public good will be served by such sales. The Department has made limited additional retail sales of electricity. The Department retains its traditional responsibilities of public advocacy before the VPSB and electricity planning on a statewide basis.
BUSINESS DEVELOPMENT
The Company has a plan of diversification into energy-related businesses intended to complement the Company's basic utility enterprise. These businesses are conducted through two subsidiaries, Green Mountain Propane Gas Company and Mountain Energy, Inc., and the Company's unregulated rental water heater activities. The Company plans to limit such diversification to 20% of the Company's consolidated revenue.
Beginning in the first quarter of 1992, the Company consolidated four of its wholly owned subsidiaries, including Green Mountain Propane and Mountain Energy, in its financial statements. The Company's prior years' financial statements have been restated to reflect this consolidation. Prior to consolidation, the operations of these subsidiaries were reported on the equity basis as they were not material in relation to the consolidated group. Also included in the financial statements, in equity in earnings of affiliates and non-utility operations, are the results of the Company's rental water heater business. None of these activities is regulated by the VPSB.
Included in equity in earnings of affiliates and non-utility operations in the Other Income section of the Statements of Consolidated Income are the results of operations of the Company's rental water heater program which is not regulated by the VPSB, and four of the Company's wholly owned subsidiaries, Green Mountain Propane Gas Company, Mountain Energy, Inc., GMP Real Estate Corporation, and Lease-Elec, Inc. (also unregulated). Summarized financial information of the Company's unregulated activities over the last two years is as follows:
For the years ended December 31 1993 1992 ---- ---- (In thousands) Revenue . . . . . . . . . . . . . . . $11,487 $11,146 Expense . . . . . . . . . . . . . . . 11,527 11,409 --------- --------- Net Income (Loss) . . . . . . . . . . ($ 40) ($ 263) ========= =========
EMPLOYEES
The Company had 387 employees, exclusive of temporary employees, as of December 31, 1993. In addition, subsidiaries of the Company had 58 employees at year end.
SEASONAL NATURE OF BUSINESS
The Company experiences its heaviest loads in the colder months of the year. Winter recreational activities, longer hours of darkness and heating loads from cold weather usually cause the Company's peak electric sales to occur in December, January or February. The 1993 peak of 307.3 MW occurred on February 1, 1993. The Company's retail electric rates are seasonally differentiated. Under this structure, retail electric rates produce average revenues per kilowatt hour during four peak season months (December through March) that are approximately 60% higher than during the eight off- season months (April through November).
EXECUTIVE OFFICERS
Executive Officers of the Company as of March 31, 1994:
Name Age
Douglas G. Hyde 51 President, Chief Executive Officer and Chairman of the Executive Committee of the Corporation since 1993. Executive Vice President, Chief Operating Officer and Director from 1989 to 1993. Executive Vice President and Director of the Corporation from 1986 to 1989.
A. Norman Terreri 60 Senior Vice President and Chief Operating Officer since 1993. Senior Vice President from 1984 to 1993. President - Mountain Energy, Inc. since December 1989.
Edwin M. Norse 48 Vice President, Chief Financial Officer and Treasurer since 1986. President-Green Mountain Propane Gas Company since October 1993.
Christopher L. Dutton 45 Vice President and General Counsel since 1993. Vice President, General Counsel and Corporate Secretary from 1989 to 1993. General Counsel and Corporate Secretary from 1984 to 1989.
Glenn J. Purcell 60 Controller since September 1986.
Thomas C. Boucher 39 Vice President-Corporate Planning since December 1992. Assistant Vice President- Energy Planning from 1986 to 1992.
Stephen C. Terry 51 Vice President-External Affairs since December 1991. Assistant Vice President- Corporate Relations from 1986 to 1991.
Walter S. Oakes 47 Assistant Vice President-Corporate Services since December 1988. Director-Customer Services from 1987 to 1988.
Robert C. Young 56 Assistant Vice President-Operations and Engineering since December 1992. Director of Engineering from August 1991 to December 1992. Director of Special Projects from August 1991 to March 1992. Prior to joining the Company, he was employed by the Burlington Electric Department for thirty- two years, including sixteen years as General Manager.
Karen K. O'Neill 42 Assistant General Counsel since December 1989. Senior Attorney from 1988 to December 1989. Corporate Attorney from 1985 to 1988.
Craig T. Myotte 39 Assistant Vice President-Operations and Maintenance since May 1991. Director- System Operations from 1986 to 1991.
John J. Lampron 49 Assistant Treasurer since July 1991. Prior to joining the Company, he was employed by Public Service Company of New Hampshire as an Assistant Vice President from 1982 to 1990.
Donna S. Laffan 44 Corporate Secretary since December 1993. Assistant Secretary from 1986 to 1993.
Officers are elected by the Board of Directors for one-year terms and serve at the pleasure of the Board of Directors.
ITEM 2.



ITEM 2. PROPERTY
GENERATING FACILITIES
The Company's Vermont properties are located in five areas and are interconnected by transmission lines of VELCO and New England Power Company. The Company wholly owns and operates eight hydroelectric generating stations with an aggregate effective capability of 35.7 MW. It also owns two gas-turbine generating stations with effective capabilities of 15.2 MW and 56.3 MW, respectively. The Company has two diesel generating stations with an aggregate effective capability of 8.4 MW, bringing wholly owned effective capability to 116.3 MW.
The Company also owns 17.9% of the outstanding common stock, and is entitled to 17.265% (90.1 MW) of the capacity of Vermont Yankee, a 1.1% (7.1 MW) joint-ownership share of the Wyman #4 plant located in Maine, a 8.8% (30.2 MW) joint-ownership share of the Stony Brook I intermediate units located in Massachusetts and an 11% (5.8 MW) joint-ownership share of the J. C. McNeil wood-fired steam plant located in Burlington, Vermont. (See "Power Resources" under Item 1 above for plant details and the table hereinafter set forth for generating facilities presently available).
TRANSMISSION AND DISTRIBUTION
The Company had, at December 31, 1993, approximately 1.5 miles of 115- kV transmission lines, 9.4 miles of 69 kV transmission lines, 5.4 miles of 44-kV and 265.1 miles of 34.5 kV transmission lines. Its distribution system included about 2,336 miles of overhead lines, 2.4 kV to 34.5 kV, and about 392 miles of underground cable of 2.4 kV to 34.5 kV. At such date, the Company owned approximately 433,150 kVa of substation transformer capacity in distribution substations, 156,775 kVa of transformer capacity in transmission substations and 1,207,299 kVa of transformers for stepdown from distribution to customer use.
The Company owns 33.8% of the Highgate transmission intertie, a 200-MW converter and transmission line utilized to transmit power from Hydro- Quebec.
The Company also owns 29.5% of the common stock and 30% of the preferred stock of VELCO which operates a high-voltage transmission system interconnecting electric utilities in the State of Vermont.
PROPERTY OWNERSHIP
The principal wholly owned plants of the Company are located on lands owned in fee by the Company. Water power and floodage rights are controlled through ownership of the necessary land in fee or under easements.
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 which, in nearly all cases, 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 by state or municipal authorities.
INDENTURE OF FIRST MORTGAGE
The Company's interests in substantially all of its properties and franchises are subject to the lien of the mortgage securing its First Mortgage Bonds.
GENERATING FACILITIES OWNED
The following table gives information with respect to generating facilities presently available in which the Company has an ownership interest. See also "Power Resources" in Item 1. Winter Capability Type Location Name Fuel MW(1)
Wholly Owned Hydro Middlesex, VT Middlesex #2 Hydro 3.4 Marshfield, VT Marshfield #6 Hydro 5.0 Vergennes, VT Vergennes #9 Hydro 2.3 W. Danville, VT W. Danville #15 Hydro 1.2
Colchester, VT Gorge #18 Hydro 3.3 Essex Jct., VT Essex #19 Hydro 7.8 Waterbury, VT Waterbury #22 Hydro 5.0 Bolton, VT DeForge #1 Hydro 8.4
Diesel Vergennes, VT Vergennes #9 Oil 4.2 Essex Jct., VT Essex #19 Oil 4.2
Gas Berlin, VT Berlin #5 Oil 56.3 Turbine Colchester, VT Gorge #16 Oil 15.2
Jointly Owned Steam Vernon, VT Vermont Yankee Nuclear 90.1(2) Yarmouth, ME Wyman #4 Oil 7.1 Burlington, VT McNeil Wood 6.6(3)
Combined Ludlow, MA Stony Brook #1 Oil/Gas 30.2(2) _____
Total Winter Capability 250.3
(1) Winter capability quantities are used since the Company's peak usage occurs during the winter months. Some units are derated for the summer months. Capability shown includes capacity and associated energy sold to other utilities.
(2) For a discussion of the impact of various power supply sales on the availability of generating facilities, see "Long-Term Power Sales."
(3) The Company's entitlement in McNeil is 5.8 MW. However, the Company receives up to 6.6 MW as a result of other owners' losses on this system.
CORPORATE HEADQUARTERS
For a discussion of the Company's operating lease for its Corporate Headquarters building, see Note I-2 of Notes to Consolidated Financial Statements.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
See the discussion under "Environmental Matters" in Item 1 concerning a notice received by the Company in 1982, under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
PART II
ITEM 5.

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Outstanding shares of the Common Stock are listed and traded on the New York Stock Exchange. The following tabulation shows the high and low sales prices for the Common Stock on the New York Stock Exchange during 1992 and 1993:
HIGH LOW
1993 First Quarter 35 5/8 31 3/8 Second Quarter 36 1/2 32 5/8 Third Quarter 36 5/8 34 3/8 Fourth Quarter 35 1/8 30 3/4
1992 First Quarter 31 1/4 29 1/4 Second Quarter 30 3/4 29 Third Quarter 33 5/8 30 Fourth Quarter 33 1/4 30 1/8
The number of common stockholders of record as of March 18, 1994, was 6,693.
Quarterly cash dividends were paid as follows for the past two years:
First Second Third Fourth Quarter Quarter Quarter Quarter ------- ------- ------- -------
1993 52 1/2 cents 52 1/2 cents 53 cents 53 cents 1992 51 1/2 cents 51 1/2 cents 52 1/2 cents 52 1/2 cents
SELECTED FINANCIAL DATA
Results of operations for the years ended December 31 - -----------------------------------------------------
Financial Condition as of December 31 - -------------------------------------
ITEM 7.


ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION 		AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS Earnings Summary -- Earnings per average share of common stock in 1993 were $2.20 as compared with $2.54 in 1992 and $2.45 in 1991. The 1993 earnings represent an earned return on average common equity of 10.3 percent. In 1992 and 1991, the earned return on equity was 12.2 and 12.5 percent, respectively.
The 1993 decrease in earnings resulted principally from a nearly two- fold increase in purchases of electricity from independent power producers mandated by federal and state law. These purchases are priced at rates set by the Vermont Public Service Board (VPSB) based on the VPSB calculations of the statewide long-term cost of electricity acquisitions avoided by such purchases. In 1993, these rates were substantially higher than the Company's overall cost of electricity.
The principal factors contributing to the earnings results in 1992 were higher retail revenues, due primarily to a rate increase of 5.6 percent that took effect in April 1992, and stable energy prices.
Operating Revenues and MWH Sales -- Operating revenues and MWH sales for the years 1993, 1992 and 1991 consisted of
1993 1992 1991 ---- ---- ---- (Dollars in Thousands) Operating Revenues: Retail . . . . . . . . . . . . . $ 130,061 $ 126,057 $ 118,021 Sales for Resale . . . . . . . . 14,441 17,258 23,663 Other . . . . . . . . . . . . . 2,751 1,925 1,871 ---------- ---------- ---------- Total Operating Revenues . . . . . $ 147,253 $ 145,240 $ 143,555 ========== ========== ========== Megawatthour Sales: Retail . . . . . . . . . . . . . 1,688,803 1,692,179 1,645,387 Sales for Resale . . . . . . . . 331,875 375,894 545,031 --------- --------- --------- Total Megawatthour Sales . . . . . 2,020,678 2,068,073 2,190,418 ========= ========= ========= Average Number of Customers: Residential . . . . . . . . . . 67,994 67,201 66,406 Commercial & Industrial . . . . 11,472 11,269 11,239 Other . . . . . . . . . . . . . 74 73 71 ------ ------ ------ Total Customers . . . . . . . . . . 79,540 78,543 77,716 ====== ====== ======
Differences in operating revenues were due to changes in the following:
1992 1991 to to 1993 1992 ---- ---- (In Thousands) Operating Revenues: Retail Rates . . . . . . . . . . . . . . . $4,269 $4,499 Retail Sales Volume . . . . . . . . . . . (265) 3,537 Resales and Other Revenues . . . . . . . . (1,991) (6,351) ------- ------- Increase in Operating Revenues . . . . . . . $2,013 $1,685 ======= =======
In 1993, total electricity sales decreased 2.3 percent due principally to a reduction in wholesale sales. Total operating revenues increased 1.4 percent in 1993 due primarily to a 5.6 percent retail rate increase that was effective in April 1992. Wholesale revenues declined 16.3 percent in 1993 due principally to the sluggish economy and the availability of inexpensive, excess power supply in New England.
In 1992, total electricity sales decreased 5.6 percent due principally to a reduction in wholesale sales. Total operating revenues increased 1.1 percent in 1992, due primarily to a 5.6 percent rate increase that was effective in April 1992, and to increased sales of electricity to retail customers reflecting colder (but normal) temperatures in 1992 and higher usage by commercial and industrial customers. These factors were principally responsible for the 6.8 percent rise in retail revenues that occurred in 1992. Wholesale revenues declined 27.1 percent in 1992 due principally to the end of a multi-year contract under which the Company sold electricity to another New England utility, the sluggish economy, and the availability of inexpensive, excess power in New England.
IBM, the Company's single largest customer, operates manufacturing facilities in Essex Junction. IBM's electricity requirements for its main plant and an adjacent plant accounted for 13.6, 13.8 and 13.0 percent of the Company's operating revenues in 1993, 1992 and 1991, respectively. No other retail customer accounted for more than one percent of the Company's revenue.
Power Supply Expenses -- Power supply expenses constituted 59.7 percent, 58.1 percent and 60.7 percent of total operating expenses for the years ended 1993, 1992 and 1991, respectively. These expenses increased by $4.1 million in 1993 (5.5 percent), and decreased by $3.4 million (4.4 percent) in 1992.
Power supply expenses increased in 1993 due primarily to a nearly twofold increase in purchases of electricity from independent power producers mandated by federal and state law. The average cost per kilowatthour of such electricity is substantially greater than the Company's embedded cost of electricity.
The decrease in power supply expenses in 1992 was principally the result of lower fuel prices, abundant and inexpensive opportunity purchases, reduced levels of wholesale electricity sales and favorable changes in the Company's power purchase contracts with Hydro-Quebec.
Other Operating Expenses -- Other operating expenses were virtually unchanged in 1993 from 1992.
Higher pension and postretirement health care benefit costs and increased regulatory commission expenses resulted in an 8.2 percent increase in other operating expenses in 1992.
Transmission Expenses -- The Company's restructuring of a series of transmission contracts produced a 3.0 percent decrease in transmission expenses in 1993.
Transmission expenses decreased 4.8 percent in 1992 for the same reason.
Maintenance Expenses -- Maintenance expenses decreased 7.3 percent in 1993 due principally to a scheduled increase in activity in various capital projects that had the effect of reducing activity by Company employees on maintenance projects.
Maintenance expenses increased 8.1 percent in 1992 due principally to scheduled increases in tree trimming expenses and hydroelectric generating facilities maintenance.
Depreciation and Amortization -- Depreciation and amortization expenses increased 6.3 percent in 1993, reflecting continuing additions to the Company's distribution facilities.
Depreciation and amortization expenses increased 14.5 percent in 1992, reflecting continuing additions to the Company's distribution facilities and the amortization of costs of conservation programs.
Income Taxes -- The effective federal tax rates for the years 1993, 1992 and 1991 were 28.9 percent, 28.8 percent and 28.5 percent, respectively. The various effects and components of the income tax provisions are detailed in Note G of the Notes to Financial Statements.
Other Income -- Other income increased 16.6 percent in 1993 due primarily to an increase in earnings of the Company's wholly owned subsidiary, Mountain Energy, Inc., and to the VPSB's disallowance in the 1992 retail rate case of approximately $400,000 in construction costs.
Diminished equity in earnings of affiliates and non-utility operations, primarily attributable to operating losses sustained by the propane subsidiary, was responsible for a 20.9 percent decrease in other income in 1992, compared to the previous year.
Interest Charges -- Interest charges were virtually unchanged in 1993 from 1992.
A 67.2 percent decrease in short-term debt interest expense, due to both lower interest rates and a reduction in short-term borrowings, was partially offset by an increase in long-term debt expense resulting in an overall decrease of 2.9 percent in interest charges in 1992.
Dividends on Preferred Stock -- Dividends on preferred stock decreased 2.4 percent in 1993 due primarily to the repurchase by the Company in 1992 of the following preferred stock: 450 shares of 4.75 percent, Class B; 450 shares of 7 percent, Class C; and 1,600 shares of 9.375 percent, Class D, Series 1.
Dividends on preferred stock decreased 2.5 percent in 1992 due primarily to the repurchase of preferred stock by the Company in 1991 of the same class and quantity.
Future Outlook -- The Company continues to implement aggressive conservation programs to mitigate the increasing demand for electricity. The Company is reviewing its future conservation plans in light of various factors, including changing avoided electricity costs, its experience and increased effectiveness in delivering conservation programs, and its total resource mix. Even with continued existing conservation programs, the Company anticipates that the demand for electricity in its service territory will grow by approximately 1.0 percent per year over the next five years.
Because the Company purchases most of its power supply from other utilities, it does not anticipate that it will incur any material direct cost increases as a result of the recently enacted Federal Clean Air legislation. Furthermore, only one of its power supply purchase contracts, which expires in 1998, relates to a generating plant that is likely to be affected by the acid rain provisions of this legislation. Overall, approximately 10 percent of the Company's committed electricity supply is expected to be affected by federal and State environmental compliance requirements.
The Company regularly reviews rates and forecasts costs. As these forecasts change, the Company will seek changes in rates that will enable it to recover operating costs.
Financial statements are prepared in accordance with generally accepted accounting principles and report operating results in terms of historic costs. This accounting provides reasonable financial statements but does not always take inflation into consideration. As rate recovery is based on these historical costs and known and measurable changes, the Company is able to receive some rate relief for inflation. It does not receive immediate rate recovery relating to fixed costs associated with Company assets. Such fixed costs are recovered based on historic figures. Any effects of inflation on plant costs are generally offset by the fact that these assets are financed through long-term debt.
Diversification -- The Company has a plan of diversification into energy-related businesses intended to complement the Company's basic utility enterprise. The Company plans to limit diversification to 20 percent of the Company's consolidated revenue.
Environmental Matters -- In recent years, public concern for the physical environment has brought about increased government regulation of the licensing and operation of electric generation, transmission and distribution facilities. The Company must meet various land, water, air and aesthetic requirements as administered by local, state and federal regulatory agencies. The Company maintains an environmental compliance and monitoring program that includes employee training, regular inspection of Company facilities, research and development projects, waste handling and spill prevention procedures and other activities. Subject to the results of developments discussed in Note I.1 of Notes to Consolidated Financial Statements concerning the Pine Street Marsh site in Burlington, Vermont, the Company believes that it is in substantial compliance with such requirements, and no material complaints concerning compliance by the Company with present environmental protection regulations are outstanding.
During 1991, the Company incurred approximately $400,000 in costs associated with the Pine Street Marsh site for technical consultants and legal assistance in connection with the United States Environmental Protection Agency's (EPA) enforcement actions at the site and insurance litigation. In its 1991 rate increase proceeding, the Company, for the first time, sought to recover costs associated with the Pine Street Marsh site in retail rates. The Department of Public Service and the Company entered into an agreement providing that the Company was entitled to recover all such costs incurred in 1991. The agreement provided that such rate recovery is not intended to serve as a precedent for retail ratemaking treatment of future costs incurred by the Company in connection with the Pine Street Marsh site. The Company's rates approved by the VPSB on April 2, 1992, reflected the 1991 Pine Street related expenditures referred to above. From January 1, 1992 through July 31, 1993, the Company incurred approximately $4.2 million in such costs associated with the Pine Street Marsh site and insurance litigation. In its 1993 rate proceeding, the Company sought to recover these costs in retail rates. The Company and the other parties to the rate proceeding entered into an agreement providing that the Company was entitled to recover all such costs incurred in the January 1, 1992 through July 31, 1993 period. The agreement provided that such rate recovery is not intended to serve as a precedent for retail ratemaking of future costs incurred by the Company in connection with the Pine Street Marsh site. This agreement, which is a part of an overall 2.9 percent rate increase settlement reached by the parties, is pending before the VPSB.
As of December 31, 1993, the Company has reserved approximately $680,000 for costs attributable to the site, other than those costs that are the subject of the two agreements between the Department and the Company mentioned above. Management expects to seek and receive ratemaking treatment for other costs incurred beyond the amounts that have been reserved. As of December 31, 1993, such other costs are approximately $4,918,000, of which $4.2 million is the subject of the agreement that is a part of the settlement of the Company's 1993 rate proceeding referred to above.
As is more fully set forth in Note I.1 of Notes to Consolidated Financial Statements, the Company is unable to predict at this time the magnitude of liability that may be imposed on it resulting from potential claims for the cost of studies undertaken by the EPA or performance of any remedial action in connection with the Pine Street Marsh site. The Company is one of several parties that the EPA has identified as potentially responsible for the cost of studying and remedying the results of releases of allegedly hazardous substances at the site. To the degree that it is held liable for such claims, the Company will pursue claims against other responsible parties seeking to ensure that they contribute appropriately to reimburse the Company for any costs incurred.
In December 1991, the Company brought suit against several previous insurers seeking recovery of all past costs and indemnity against future liabilities associated with the environmental problems at the site. The parties to the action are engaged in discovery and motions practice.
The Company has reached a confidential settlement with one of the defendants, which provided the Company with second layer excess liability coverage for a seven-month period in 1976. The Company has also reached a confidential agreement in principle with another insurance company defendant that provided the Company with comprehensive general liability insurance between 1976 and 1982, and with environmental impairment liability insurance from 1981 to 1984. These policies were in place in 1982 when EPA first notified the Company that it might be a potentially responsible party at the Pine Street site.
LIQUIDITY AND CAPITAL RESOURCES Construction -- The Company's capital requirements result from the need to construct facilities or to invest in programs to meet anticipated customer demand for electric service. The policy of the Company is to increase diversification of its power supply and other resources through various means, including power purchase and sales arrangements and relying on sources that represent relatively small additions to the Company's mix to satisfy customer requirements. This permits the Company to meet its financing needs in a flexible, orderly manner. Planned expenditures over the next five years will be primarily for distribution and conservation projects.
Capital expenditures over the past three years and forecasted for the next five years are as follows:
Total Net Actual Generation Transmission Distribution Conservation Other	Expenditures (Dollars in thousands and net of AFUDC and Customer Advances For Construction)
1991 $2,038 $1,682 $7,628 $2,269 $2,564 $16,181 1992 868 1,766 7,320 3,144 2,925 16,023 1993 1,747 1,605 9,093 8,136 2,937 23,518 Forecasted 1994 $ 709 $ 829 $7,849 $6,975 $3,618 $19,980 1995 7,567 999 7,132 6,776 2,402 24,876 1996 1,978 1,499 7,301 6,497 2,251 19,526 1997 1,579 999 7,386 5,867 2,386 18,217 1998 1,579 999 7,386 5,430 2,386 17,780
Other Cash Requirements -- In its January 1991 rate order, the VPSB required that the Company set up a special trust account for monies currently accrued for postretirement health care benefits. This fund totaled $2.1 million at December 31, 1993, and $3.3 million at January 31, 1994. In 1994, the Company may devote $1 million to $4 million to unregulated investments.
Insurance Settlement -- In January 1993, the Company settled a long- disputed claim with a former medical benefits insurance carrier relating to overcharged premiums dating back to 1984, resulting in an agreement under which the carrier paid the Company $360,000. The Company received this payment in the first quarter of 1993.
Rates -- On October 1, 1993, the Company filed a request with the VPSB to increase retail rates by 8.6 percent. The increase is needed primarily to cover the cost of buying power from independent power producers, the cost of energy conservation programs, the cost of plant additions made in the past two years, and costs incurred in 1992 and 1993 associated with the Company's response to the EPA's RI/FS and proposed remedy at the Pine Street Marsh site and with the Company's litigation against its previous insurers seeking recovery of past costs incurred and indemnity against future liabilities in connection with the site. On January 28, 1994, the Company and the other parties in the proceeding reached a settlement agreement providing for a 2.9 percent retail rate increase effective June 15, 1994, and a target return on equity for utility operations of 10.5 percent. The settlement agreement also provided for the Company's recovery in rates of $4.2 million in costs associated with the Pine Street Marsh site, as described herein above. The agreement must be reviewed and approved by the VPSB before it can take effect.
Financing and Capitalization -- For the period 1991 through 1993, internally generated funds, after payment of dividends, provided approximately 47 percent of total capital requirements for construction, sinking funds and other requirements. The Company anticipates that for the period 1994-1998, internally generated funds will provide approximately 67 percent of total capital requirements.
In November of 1993, the Company sold $20 million of its first mortgage bonds in two components -- $15 million that will mature in 2018 and $5 million that will mature in 2000. The 2018 and 2000 bonds will bear interest at the rate of 6.7 percent and 5.71 percent, respectively. The proceeds from the sale were used to refinance existing debt, to finance construction and conservation expenditures, and for other corporate purposes.
At December 31, 1993, the Company's capitalization consisted of 51.6 percent common equity, 43.4 percent long-term debt and 5.0 percent preferred equity. The Company has a comprehensive capital plan to maintain approximately this balance of common equity, long-term debt and preferred equity.
The Company anticipates issuing additional shares of its common stock in 1994. The Company has not determined the date or the amount of the stock issuance.
The Company's first mortgage securities are rated "A-" by Standard & Poor's. This rating was affirmed in November of 1993 by Standard & Poor's following its annual review of the Company. Standard & Poor's changed its "outlook" of the Company from "stable" to "negative," reflecting Standard & Poor's assessment that the electric utility industry is becoming increasingly more competitive. The Company's first mortgage securities are rated "A" by Duff & Phelps.
See Note F of Notes to Consolidated Financial Statements for a discussion of bank lines of credit available to the Company.
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
GREEN MOUNTAIN POWER CORPORATION INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
Page Financial Statements
Statements of Consolidated Income For the Years Ended December 31, 1993, 1992 and 1991 39
Consolidated Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991 40
Consolidated Balance Sheets as of December 31, 1993 and 1992 41-42
Consolidated Capitalization data as of December 31, 1993 and 1992 43
Notes to Consolidated Financial Statements 44-63
Report of Independent Public Accountants 64
Schedules
For the Years Ended December 31, 1993, 1992 and 1991:
V Property, Plant and Equipment 65-67
VI Accumulated Depreciation and Amortization of Property, Plant and Equipment 68
VIII Valuation and Qualifying Accounts and Reserves 69
IX Short-Term Borrowings 70
X Supplementary Income Statement Information 71
All other schedules are omitted as they are either not required, not applicable or the information is otherwise provided.
Consents and Reports of Independent Public Accountants
KPMG Peat Marwick 109 Arthur Andersen & Co. 110-111
STATEMENTS OF CONSOLIDATED INCOME
GREEN MOUNTAIN POWER CORPORATION For the Years Ended December 31
CONSOLIDATED STATEMENTS OF CASH FLOW
GREEN MOUNTAIN POWER CORPORATION For the Years Ended December 31
CONSOLIDATED BALANCE SHEETS
GREEN MOUNTAIN POWER CORPORATION December 31
GREEN MOUNTAIN POWER CORPORATION December 31
CONSOLIDATED CAPITALIZATION DATA
GREEN MOUNTAIN POWER CORPORATION December 31
Notes to Consolidated Financial Statements
A. Significant Accounting Policies 1. System of Accounts The Company's accounting records, rates, operations and certain other practices of its electric utility business are subject to the regulatory authority of the Federal Energy Regulatory Commission (FERC) and the Vermont Public Service Board (VPSB).
2. Basis of Presentation Included in equity in earnings of affiliates and non-utility operations in the Other Income section of the Statements of Consolidated Income are the results of operations of the Company's rental water heater program, which is not regulated by the VPSB, and four of the Company's wholly owned subsidiaries, Green Mountain Propane Gas Company, Mountain Energy, Inc., GMP Real Estate Corporation, and Lease-Elec, Inc. (also unregulated). Summarized financial information is as follows: For the years ended December 31 1993 1992 ---- ---- (In thousands) Revenue . . . . . . . . . . . . . . . $11,487 $11,146 Expense. . . . . . . . . . . . . . . . 11,527 11,409 --------- --------- Net Income (Loss) . . . . . . . . . . ($ 40) ($ 263) ========= =========
The Company carries its investments in various associated companies -- Vermont Yankee Nuclear Power Corporation (Vermont Yankee), Vermont Electric Power Company, Inc. (VELCO), New England Hydro-Transmission Corporation, and New England Hydro-Transmission Electric Company -- at equity.
3. Statements of Cash Flows The following amounts of interest (net of amounts capitalized) and income taxes were paid for the years ending December 31: 1993 1992 1991 ---- ---- ---- (In thousands) Interest . . . . . . . . . . . . . . . . $6,206 $7,683 $7,254 Income Taxes (Net of refunds) . . . . . $1,920 $3,511 $3,695
4. Utility Plant The cost of plant additions includes all construction-related direct labor and materials, as well as indirect construction costs including the cost of money (Allowance for Funds Used During Construction or AFUDC). The costs of renewals and betterments of property units are capitalized; the costs of maintenance, repairs and replacements of minor property items are charged to maintenance expense; the costs of units of property removed from service, net of removal costs and salvage, are charged to accumulated depreciation.
AFUDC represents the composite interest and equity costs of capital funds used to finance construction. AFUDC, a non-cash item, is recognized as a cost of "Utility Plant" with offsetting credits to "Other Income" and "Interest Charges." This is in accordance with established regulatory ratemaking practice under which a utility is permitted a return on, and the recovery of, these capital costs through their ultimate inclusion in rate base and in the provisions for depreciation.
When Construction Work in Progress (CWIP) is included in rate base and the utility is recovering the cost of financing this construction through rates, no AFUDC is included in the cost of such construction. The VPSB generally allows CWIP in rate base for short-term construction projects and projects for which completion is imminent.
AFUDC, which is compounded semi-annually, was calculated using weighted average rates of 7.2 percent, 8.9 percent and 7.6 percent for the years 1993, 1992 and 1991, respectively.
5. Depreciation The Company provides for depreciation on the straight-line method based on the cost and estimated remaining service life of the depreciable property outstanding at the beginning of the year.
The annual depreciation provision was approximately 3.6 percent, 3.5 percent and 3.5 percent of total depreciable property at the beginning of the year for 1993, 1992 and 1991, respectively.
6. Operating Revenues Operating revenues consist principally of sales of electric energy. The Company records accrued utility revenues, based on estimates of electric service rendered and not billed at the end of an accounting period, in order to match revenues with related costs.
7. Deferred Charges In a manner consistent with authorized or expected ratemaking treatment, the Company defers and amortizes certain replacement power, maintenance and other costs associated with the Vermont Yankee nuclear plant. In addition, the Company accrues other replacement power expenses to reflect more accurately its cost of service to better match revenues and expenses consistent with regulatory treatment.
At December 31, 1993 deferred charges totaled $42.3 million, consisting of charges for conservation programs, response and litigation costs attributable to the Pine Street Marsh site discussed in Note I.1, repair costs for and relicensing of the Essex hydroelectric facility, repair costs for the Vergennes hydroelectric facility, Hydro-Quebec power contract negotiations and support charges, regulatory deferrals of storm damages, PCB clean-up, regulatory deferrals of rights-of-way maintenance, costs associated with the 1993 scheduled Vermont Yankee outage, postretirement health care costs, and various other projects and deferrals.
8. Earnings Per Share Earnings per share are based upon the weighted average number of shares of common stock outstanding during each year.
9. Major Customers The Company had one major retail customer, IBM, metered at two locations, that accounted for 13.6, 13.8 and 13.0 percent of operating revenues in 1993, 1992 and 1991, respectively.
10. Pension and Retirement Plans The Company has a defined benefit pension plan covering substantially all of its employees. The retirement benefits are based on the employees' level of compensation and length of service. The Company's policy is to fund all pension costs accrued. The Company records annual expense in accordance with methods approved in the rate-setting process.
Net pension costs reflect the following components and assumptions: 1993 1992 1991 ---- ---- ---- (Dollars in thousands)
Service cost-benefits earned during the period . $ 748 $ 676 $ 621 Interest cost on projected benefit obligations . 1,593 1,466 1,275 Actual (return) loss on plan assets . . . . . . . (3,107) (1,743) (3,109) Net amortization and deferral . . . . . . . . . . 1,141 (77) 1,440 Adjustment due to actions of regulator . . . . . 337 430 153 ------ ------- ------ Net periodic pension cost funded and recognized . $ 712 $ 752 $ 380 ====== ======= ======
Assumptions used to determine pension costs in 1993, 1992 and 1991 were: Discount rate . . . . . . . . . . . . . . . . 8.0% 8.0% 8.0% Rate of increase in future compensation levels 6.0% 6.0% 6.0% Expected long-term rate of return on assets . 9.0% 9.0% 9.0%
The following table sets forth the Plan's funded status as of December 31: 1993 1992 1991 ---- ---- ---- (In thousands) Actuarial present value of benefit obligations: Accumulated benefit obligations, including vested benefits of $16,825, $15,100 and $12,567, respectively . . . . . ($17,105) ($15,262) ($12,704) ========= ========= ========= Projected benefit obligations for service rendered to date . . . . . . . . . ($21,002) ($19,235) ($16,563) Plan assets at fair value . . . . . . . . . . . 23,981 21,167 19,675 ------- ------- ------- Assets in excess of projected benefit obligations . . . . . . . . . . . . . 2,979 1,932 3,112 Unrecognized net loss (gain) from past experience different from that assumed . . . (272) 559 399 Prior service cost not yet recognized in net periodic pension cost . . . . . . . . . . . . 1,885 2,028 842 Unrecognized net asset at transition being recognized over 16.47 years . . . . . . (2,162) (2,391) (2,619) Adjustment due to actions of regulator . . . . . (2,430) (2,128) (1,734) ------ ------ ----- Prepaid pension cost included in other assets . $ --- $ --- $ --- ====== ====== ======
The Company has evaluated the effect of a reduction in the discount rate and compensation trend rate and has concluded that the net effect of such changes is insignificant.
The plan assets consist primarily of cash equivalent funds, fixed income securities and listed equity securities.
The Company also has a supplemental pension plan for certain employees. Pension costs for the years ended December 31, 1993, 1992 and 1991 were $384,000, $377,000 and $352,000, respectively, under this plan. This plan is supported through insurance contracts.
11. Fair Value of Financial Instruments If the first mortgage bonds, debentures, and preferred stock outstanding at December 31, 1993 were refinanced using new issue debt rates of interest, which are generally lower than the Company's outstanding rates, the present value of those obligations would differ from the amounts outstanding on the December 31, 1993 balance sheet by nine percent. The Company does not anticipate a refinancing; however, if such an event were to occur, there would be no gain or loss, inasmuch as under established regulatory precedent, any such difference would be reflected in rates and have no effect upon income.
12. Postretirement Health Care Benefits The Company provides certain health care benefits for retired employees and their dependents. Employees become eligible for these benefits if they reach normal retirement age while working for the Company.
On January 1, 1993, the Company adopted the standard on accounting for postretirement health care and other benefits, SFAS 106, which requires the Company to use accrual accounting for postretirement benefits other than pensions. Prior to 1993, the Company recognized the cost of postretirement health care benefits by recording an amount equivalent to that which had been allowed in rates. The difference between total cost and claims paid was accrued on the balance sheet.
In its January 4, 1991 rate order, the VPSB required the Company to establish a fund in which the Company will accumulate monies for postretirement health care expenses. At December 31, 1993, the Company had deposited $2.1 million in the investment fund, which is included in other investments in the accompanying balance sheet. In January 1994, the Company fully funded its accrued postretirement benefit cost of $3.3 million. In order to maximize the tax deductible contributions that are allowed under IRS regulations, the Company has amended its pension plan and established separate VEBA trusts for its union and nonunion employees.
The Company will seek and expects to receive rate recovery for all amounts expended for postretirement health care benefits.
Net postretirement benefits costs for 1993 reflect the following components and assumptions: (In thousands) Accumulated postretirement benefit obligation: Current retirees . . . . . . . . . . . . . . . . . ($ 3,628) Participants currently eligible . . . . . . . . . (2,288) All others . . . . . . . . . . . . . . . . . . . . (4,789) -------- Total accumulated postretirement benefit obligation . (10,705) Plan assets at fair value . . . . . . . . . . . . . . 0 ------- Accumulated postretirement benefit obligation in excess of plan assets . . . . . . . . . . . . . . . . . . (10,705) Unrecognized transition obligation . . . . . . . . . 6,845 Unrecognized net loss (gain) . . . . . . . . . . . . 538 -------- Accrued postretirement benefit cost . . . . . . . . . $3,322 ======== Net periodic postretirement benefit cost for 1993 includes the following components: (In thousands) Service cost . . . . . . . . . . . . . . . . . . . . $ 438 Interest cost . . . . . . . . . . . . . . . . . . . 940 Amortization and deferral . . . . . . . . . . . . . 380 -------- Total net periodic postretirement benefit cost . . . $ 1,758 ========
For measurement purposes, a 14.25 percent annual rate of increase in the per capita cost of covered benefits was assumed for 1993; the rate was assumed to decrease gradually to 5.5 percent by the year 2000 and remain at that level thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. For example, increasing the assumed health care cost trend rate by one percentage point would increase the accumulated postretirement benefit obligation as of December 31, 1993 by $1.7 million and the aggregate of the service and interest components of net periodic postretirement benefit cost for the year ended December 31, 1993 by $241,000. The weighted average discount rate used in determining the accumulated postretirement benefit obligation was 8 percent at December 31, 1993.
The Company has evaluated the effect of a reduction in the discount rate and medical care trend rate and has concluded that the net effect of such changes is insignificant.
13. Deferred Credits The Company has deferred credits and other long-term liabilities of $22.1 million, consisting of operating lease equalization, general liabilities and damages reserves and accruals for employee benefits.
B. Investments in Associated Companies The Company accounts for investments in the following companies by the equity method: Investment in Equity Percent Ownership December 31, at December 31, 1993 1993 1992 -------------------- ---- ---- (In thousands) VELCO - Common . . . . . . . . . 29.5% $ 1,816 $ 1,818 - Preferred . . . . . . . 30.0% 1,572 1,736 ------- ------ Total VELCO . . . . . . . . . . 3,388 3,554 Vermont Yankee - Common . . . . 17.9% 9,745 9,731 New England Hydro-Transmission - Common . . . . . . . . . . 3.18% 1,408 1,489 New England Hydro-Transmission Electric - Common . . . . . 3.18% 2,345 2,396 -------- -------- $16,886 $17,170 ======= ========
Undistributed earnings in associated companies totaled $1,140,000 at December 31, 1993. VELCO VELCO is a corporation engaged in the transmission of electric power within the state of Vermont. VELCO has entered into transmission agreements with the State of Vermont and other 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. The Company's purchases of transmission services from VELCO were $8.0 million, $7.8 million and $7.8 million for the years 1993, 1992 and 1991, respectively. Pursuant to VELCO's Amended Articles of Association, the Company is entitled to approximately 30 percent of the dividends distributed by VELCO. The Company has recorded its equity in earnings on this basis and also is obligated to provide its proportionate share of the equity capital requirements of VELCO through continuing purchases of its common stock, if necessary. Summarized financial information for VELCO is as follows: December 31, --------------------------- 1993 1992 1991 ---- ---- ---- (In thousands) Company's equity in net income . . . . . . . $ 406 $ 448 $ 466 ======= ======= ====== Total assets . . . . . . . . . . . . . . . . $70,199 $70,821 $69,949 Less: Liabilities and long-term debt . . . . . 58,806 58,889 57,395 ------- ------- ------- Net assets . . . . . . . . . . . . . . . . . $11,393 $11,932 $12,554 ======= ======= ======= Company's equity in net assets . . . . . . . $ 3,388 $ 3,554 $ 3,738 ======= ======= ======= Vermont Yankee The Company is responsible for 17.3 percent of Vermont Yankee's expenses of operations, including costs of equity capital and estimated costs of decommissioning, and is entitled to a similar share of the power output of the nuclear plant, which has a net capacity of 520 megawatts. Vermont Yankee's current estimate of decommissioning is approximately $253 million in 1993 dollars, of which $99 million has been funded. At December 31, 1993, the Company's portion of the net unfunded liability was $27 million, which it expects will be recovered through rates over Vermont Yankee's remaining operating life. As a sponsor of Vermont Yankee, the Company also is obligated to provide 20 percent of capital requirements not obtained by outside sources. During 1993, the Company incurred $27.7 million in Vermont Yankee annual capacity charges, which included $1.6 million for interest charges. The Company's share of Vermont Yankee's long-term debt at December 31, 1993 was $13.8 million.
The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $9.4 billion. Any liability beyond $9.4 billion is indemnified under an agreement with the NRC. The first $200 million of liability coverage is the maximum provided by private insurance. The Secondary Financial Protection program is a retrospective insurance plan providing additional coverage up to $9.2 billion per incident by assessing retrospective premiums of $79.3 million against each of the 116 reactor units in the United States that are currently subject to the Program, limited to a maximum assessment of $10 million per incident per nuclear unit in any one year. The maximum assessment is to be adjusted at least every five years to reflect inflationary changes.
The above insurance covers all workers employed at nuclear facilities prior to January 1, 1988, for bodily injury claims. Vermont Yankee has purchased a master worker insurance policy with limits of $200 million with one automatic reinstatement of policy limits to cover workers employed on or after January 1, 1988. Vermont Yankee's estimated contingent liability for a retrospective premium on the master worker policy as of December 1993 is $3.1 million. The secondary financial protection program referenced above provides coverage in excess of the Master Worker policy.
Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL II) to cover the costs of property damage, decontamination or premature decommissioning resulting from a nuclear incident. All companies insured with NEIL II are subject to retroactive assessments if losses exceed the accumulated funds available to NEIL II. The maximum potential assessment against Vermont Yankee with respect to losses arising during the current policy year is $5.8 million at the time of the first loss and $12.3 million at the time of a subsequent loss. Vermont Yankee's liability for the retrospective premium adjustment for any policy year ceases six years after the end of that policy year unless prior demand has been made. Summarized financial information for Vermont Yankee is as follows: December 31, 1993 1992 1991 ---- ---- ---- (In thousands) Earnings: Operating revenues . . . . . . . . . . . $180,145 $175,919 $151,722 Net income applicable to common stock . 7,793 7,921 8,490 Company's equity in net income . . . . . 1,425 1,415 1,516 Total assets . . . . . . . . . . . . . . . $469,770 $438,208 $417,618 Less: Liabilities and long-term debt . . . . 415,606 383,933 363,354 -------- -------- -------- Net assets . . . . . . . . . . . . . . . . $ 54,164 $ 54,275 $ 54,264 ======== ======== ======== Company's equity in net assets . . . . . . $ 9,745 $ 9,731 $ 9,729 ======== ======== ======== C. Common Stock Equity The Company maintains a Dividend Reinvestment and Stock Purchase Plan (DRIP) under which 394,112 shares were reserved and unissued at December 31, 1993. The Company also funds an Employee Savings and Investment Plan (ESIP). At December 31, 1993, there were 47,067 shares reserved and unissued under the ESIP.
In October 1991, the Company issued 429,600 additional shares of common stock at a price of $28.25 per share. The net proceeds were used to reduce the Company's outstanding short-term debt, to finance planned capital additions and to maintain an appropriate capital structure.
In May 1993, the Company amended its Articles of Association increasing the number of authorized shares of common stock from 6,000,000 to 10,000,000.
Changes in common stock equity for the years ended December 31, 1991, 1992 and 1993 are as follows:
Dividend Restrictions Certain restrictions on the payment of cash dividends on common stock are contained in the indentures relating to long-term debt and in the Restated Articles of Association. Under the most restrictive of such provisions, $17.9 million of retained earnings were free of restrictions at December 31, 1993.
The properties of the Company include several hydroelectric projects licensed under the Federal Power Act, with license expiration dates ranging from 1993 to 2022. At December 31, 1993, $259,000 of retained earnings had been appropriated as excess earnings on hydroelectric projects as required by Section 10(d) of the Federal Power Act.
D. Preferred Stock The holders of the preferred stock are entitled to specific voting rights with respect to the placement of restrictions on certain types of corporate actions. They are also entitled to elect the smallest number of directors necessary to constitute a majority of the Board of Directors in the event of preferred stock dividend arrearages equivalent to or exceeding four quarterly dividends. Similarly, the holders of the preferred stock are entitled to elect two directors in the event of a default in any purchase or sinking fund requirements provided for any class of preferred stock.
Certain classes of preferred stock are subject to annual purchase or sinking fund requirements. The sinking fund requirements are mandatory. The purchase fund requirements are mandatory, but holders may elect not to accept the purchase offer. The redemption or purchase price to satisfy these requirements may not exceed $100 per share plus accrued dividends. All shares redeemed or purchased in connection with these requirements must be canceled and may not be reissued. The annual purchase and sinking fund requirements for certain classes of preferred stock are:
Purchased and Sinking Fund 4.75%, Class B . . . . . . . . December 1 450 Shares 7%, Class C . . . . . . . . . December 1 450 Shares 9.375%, Class D, Series 1 . . December 1 1,600 Shares
The 8.625%, Class D, Series 3, preferred stock issued in September 1990, requires no sinking fund.
Under the Restated Articles of Association relating to Redeemable Cumulative Preferred Stock, the annual aggregate amounts of purchase and sinking fund requirements for the next five years are $250,000 for each of the years 1994 and 1995, and $1,650,000 for the years 1996 - 1998.
All of the classes of preferred stock are redeemable at the option of the Company or, in the case of voluntary liquidation, at various prices on various dates. The prices include the par value of the issue plus any accrued dividends and a redemption premium. The redemption premium for Class B, C and D, Series 1, is $1.00 per share. The redemption premium for the Class D, Series 3, is $5.751 per share until September 1, 1994; $4.793 per share from September 1, 1994 to September 1, 1995; $3.835 per share from September 1, 1995 to September 1, 1996; $2.877 per share from September 1, 1996 to September 1, 1997; $1.919 per share from September 1, 1997 to September 1, 1998; and $0.916 per share from September 1, 1998 to September 1, 1999, after which there is no redemption premium.
In May 1993, the Company amended its Articles of Association authorizing a new class of preferred stock, Class E, which may be divided into and issued in series. No shares of Class E preferred stock were issued as of December 31, 1993.
E. Long-term Debt Utility Substantially all of the property and franchises of the Company are subject to the lien of the indenture under which first mortgage bonds have been issued. The annual sinking fund requirements (excluding amounts that may be satisfied by property additions) and long-term debt maturities for the next five years are: Sinking Funds Maturities Total ------- ---------- ----- (In thousands)
1994 . . . . . . . . . . . . . . $1,800 $ --- $1,800 1995 . . . . . . . . . . . . . . 4,833 --- 4,833 1996 . . . . . . . . . . . . . . 4,833 3,000 7,833 1997 . . . . . . . . . . . . . . 3,500 1,334 4,834 1998 . . . . . . . . . . . . . . 3,500 3,000 6,500
Non-Utility At December 31, 1993, Green Mountain Propane Gas Company, the Company's propane subsidiary, had long-term debt of $4,125,000, which was secured by substantially all of the subsidiary's assets. The annual sinking fund requirements and maturities for the next three years are:
Sinking Funds Maturities Total (In thousands)
1994 . . . . . . . . . . . . . $1,100 $ --- $1,100 1995 . . . . . . . . . . . . . 1,100 --- 1,100 1996 . . . . . . . . . . . . . 550 1,375 1,925
F. Short-term Debt Utility At December 31, 1993, the Company had lines of credit with five banks totaling $30.5 million, with borrowings outstanding of $19.0 million. Borrowings under these lines of credit are at interest rates ranging from less than prime to the prime rate. The Company has fee arrangements on its lines of credit ranging from 1/4 to 3/8 percent and no compensating balance requirements. These lines of credit are subject to periodic review and renewal during the year by the various banks.
Non-Utility At December 31, 1993, Green Mountain Propane Gas Company, the Company's propane subsidiary, had a line of credit with a bank for $2.0 million, with borrowings outstanding of $400,000.
G. Income Taxes Utility On January 1, 1993, the Company adopted the standard on accounting for income taxes, SFAS 109, which requires an asset and liability approach for financial accounting and reporting for income taxes.
When implementing SFAS 109 the Company created additional deferred tax assets of $4.8 million and deferred tax liabilities of $5.6 million to give recognition to certain temporary differences previously not recognized in the Company's financial statements. These additional deferred taxes will be collected from or returned to ratepayers in future periods and, accordingly, the Company recognized a regulatory liability and regulatory asset related to income taxes of $4.8 million and $5.6 million, respectively. The implementation of SFAS 109 on January 1, 1993, and the application of SFAS 109 had no material impact on the Company's results of operations or cash flows in the twelve months ended December 31, 1993. Additionally, the Company does not believe SFAS 109 will significantly impact future results of operations or cash flows based on current ratemaking policy.
The implementation of SFAS 109 also requires the Company to consider now the future utilization of deferred tax assets. If there is doubt that the Company will be able to utilize these future tax benefits, it might be necessary to establish a valuation allowance. The Company has concluded that it is not necessary at this time to establish a valuation allowance. The Company has been in a tax-paying position for approximately ten years and does not foresee future events that will alter the Company's capacity to utilize these deductions when intended.
The temporary differences which gave rise to the net deferred tax liability at January 1, 1993 and December 31, 1993, were as follows:
At January 1, At December 31, 1993 1993 ------------- --------------- (In thousands) Deferred Tax Assets Contributions in aid of construction. . $ 4,584 $ 5,094 Deferred compensation and postretirement benefits . . . . . . . 3,046 3,387 Alternative minimum tax credit . . . . 305 749 Excess deferred taxes . . . . . . . . . 2,287 2,188 Unamortized investment tax credits . . 2,528 2,402 Other . . . . . . . . . . . . . . . . . 2,077 1,018 ------- ------- $14,827 $14,838 ------- ------- Deferred Tax Liabilities Property-related and other . . . . . . $22,659 $25,090 Demand side management costs . . . . . 2,856 5,841 Unamortized investment tax credit . . . 5,956 5,672 Reversal of previously flowed-through tax depreciation . . . . . . . . . . 4,865 4,182 AFUDC equity basis adjustment . . . . . 771 726 -------- -------- 37,107 41,511 -------- -------- Net accumulated deferred income tax asset (liability) . . . . . . . . . . ($22,280) ($26,673) ========= =========
The following table reconciles the change in the net accumulated deferred income tax liability to the deferred income tax expense included in the income statement for the period:
Net change in deferred income tax liability per above table . . . $4,393 Change in income tax related regulatory assets and liabilities. . 503 Other adjustments . . . . . . . . . . . . . . . . . . . . . . . . 849 ------ Deferred income tax expense for the period . . . . . . . . . . . $5,745 ======
The components of the provision for income taxes are: Year Ended December 31, 1993 1992 1991 ---- ---- ---- (In thousands) Current state income taxes . . . . . . . $ 134 $ 796 $ 991 Deferred state income taxes . . . . . . 1,225 716 332 Current federal income taxes . . . . . . 369 3,007 3,730 Deferred federal income taxes . . . . . 4,804 2,678 1,243 Investment tax credits -- net . . . . . (284) (284) (276) ------- ------- -------- Total income taxes . . . . . . . . . . . 6,248 6,913 6,020 Amounts included in "Other income" . . . 1 2 2 ------- ------- ------- Income taxes charged to operations . . . $6,249 $6,915 $6,022 ======= ======= =======
The following table details the components of the provisions for deferred federal income taxes: Year Ended December 31, 1993 1992 1991 ---- ---- ---- (In thousands) Deferred purchase power costs . . . . . $ 904 $ 475 $ (606) Excess tax depreciation . . . . . . . . 1,300 1,512 1,497 Demand side management . . . . . . . . 1,918 733 584 State tax benefit . . . . . . . . . . . (416) (211) (52) Contributions in aid of construction . (404) (746) (293) Supplemental benefit plans . . . . . . (182) (42) (383) Prepaid property taxes . . . . . . . . --- 8 36 Pine Street . . . . . . . . . . . . . . 817 237 152 Other . . . . . . . . . . . . . . . . . 867 712 308 ------- ------- ------- $4,804 $2,678 $1,243 ======= ======= =======
Total federal income taxes differ from the amounts computed by applying the statutory tax rate to income before taxes. The reasons for the differences are: Year Ended December 31, 1993 1992 1991 ---- ---- ---- (In thousands) Income before income tax . . . . . . . $16,880 $18,765 $16,476 Federal statutory rate . . . . . . . . 34% 34% 34% Computed "expected" federal income taxes . . . . . . . . . . . . $ 5,739 $ 6,380 $ 5,602 Increase (decrease) in taxes resulting from: Tax versus book depreciation . . . . 327 357 357 Dividends received and paid credit . (580) (597) (634) AFUDC - equity funds . . . . . . . . (93) (63) (77) Amortization of ITC . . . . . . . . (284) (284) (276) State tax benefit . . . . . . . . . (462) (514) (450) Excess deferred taxes . . . . . . . (60) (60) (60) Other . . . . . . . . . . . . . . . 302 182 235 ------- ------- ------- Total federal income taxes . . . . . . $4,889 $5,401 $4,697 ======= ======= ======= Effective federal income tax rate . . 28.9% 28.8% 28.5%
Non-Utility The Company's non-utility subsidiaries had accumulated deferred income taxes of $2.3 million on its balance sheet at December 31, 1993, largely attributable to property-related transactions.
The components of the provision for income taxes for the non-utility operations are: Year Ended December 31, 1993 1992 1991 ---- ---- ---- (In thousands) State income taxes . . . . . . . . . . $ (58) $(104) $ (40) Federal income taxes . . . . . . . . . (224) (314) (150) Investment tax credits . . . . . . . . (45) (45) (61) ------ ------ ------ Income taxes charged to operations . . $(327) $(463) $(251) ====== ====== ======
Total federal income taxes differ from the amounts computed by applying the statutory rate to income before taxes, primarily attributable to state tax benefits.
The effective federal income tax rates for the non-utility operations were 34.2 percent, 33.3 percent and 43.1 percent for the years ended 1993, 1992 and 1991, respectively.
H. Quarterly Financial Information (Unaudited) The following quarterly financial information, in the opinion of management, includes all adjustments necessary to a fair statement of results of operations for such periods. Variations between quarters reflect the seasonal nature of the Company's business and the timing of rate changes.
1993 Quarter Ended March June Sept. Dec. Total ----- ---- ----- ---- ----- (Amounts in thousands, except per share) Operating Revenues . . . . . . $40,751 $33,427 $35,647 $37,428 $147,253 Operating Income . . . . . . . 5,160 2,093 3,075 4,498 14,826 Net Income . . . . . . . . . . 4,302 966 2,051 3,312 10,631 Net Income Applicable to Common Stock . . . . . . . . 4,099 763 1,848 3,110 9,820 Earnings per Average Share of Common Stock . . . . . . . . $0.93 $0.17 $0.41 $0.69 $2.20 Weighted Average Number of Common Shares Outstanding . 4,415 4,442 4,470 4,503 4,457
1992 Quarter Ended March June Sept. Dec. Total ----- ---- ----- ---- ----- (Amounts in thousands, except per share) Operating Revenues . . . . . . $39,476 $33,288 $33,911 $38,565 $145,240 Operating Income . . . . . . . 5,636 2,420 3,888 4,468 16,412 Net Income . . . . . . . . . . 4,060 1,585 2,766 3,441 11,852 Net Income Applicable to Common Stock . . . . . . . . 3,852 1,377 2,558 3,234 11,021 Earnings per Average Share of Common Stock . . . . . . . . $0.89 $0.32 $0.59 $0.74 $2.54 Weighted Average Number of Common Shares Outstanding . 4,305 4,329 4,359 4,386 4,345
I. Commitments and Contingencies 1. Environmental Matters In 1982, the United States Environmental Protection Agency (EPA) notified the Company that the EPA, pursuant to the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA), was considering spending public funds to investigate and take corrective action involving claimed releases of allegedly hazardous substances at a site identified as the Pine Street Marsh in Burlington, Vermont. On part of this site was located a manufactured-gas facility owned and operated by a number of separate enterprises, including the Company, from the late 19th century to 1967. In its notice, the EPA stated that the Company may be a "potentially responsible party" (PRP) under CERCLA from which reimbursement of costs of investigation and of corrective action may be sought. On February 23, 1988, the Company received a Special Notice letter from the EPA stating that the letter constituted a formal demand for reimbursement of costs, including interest thereon, that were incurred and were expected to be incurred in response to the environmental problems at the site.
On December 5, 1988, the EPA brought suit against the Company, New England Electric System, and Vermont Gas Systems, Inc. in the United States District Court for the District of Vermont seeking reimbursement for costs it incurred in conducting activities in 1985 to remove allegedly hazardous substances from the site, and requested a declaratory judgment that the Company and the other defendants are liable for all costs that have been incurred since the removal and that continue to be incurred in responding to claims of releases or threatened releases from the Maltex Pond Area -- the portion of the site where the removal action occurred. The complaint specifically alleged that the EPA expended at least $741,000 during the 1985 removal action and sought interest on this amount from the date the funds were expended and costs of litigation, including attorneys' fees. The Company entered a cross-claim against New England Electric System and third-party claims against UGI Corporation, Southern Union Corporation, the State of Vermont, and an individual property owner at the site for recovery of its response costs and for contribution. Fourth-party defendants subsequently were joined.
In July 1990, the Company and other parties signed a proposed Consent Decree settling the removal action litigation. All 14 settling defendants contributed to the aggregate settlement amount of $945,000. Individual contributions were treated as confidential under the proposed Consent Decree.
On December 26, 1990, upon the unopposed motion of the United States, the Consent Decree was entered by the Court.
During the summer and fall of 1989, the EPA conducted the initial phase of the Remedial Investigation (RI) and commenced the Feasibility Study (FS) relating to the site. In the fall of 1990 and in 1991, the EPA conducted a second phase of RI work and studied the treatability of soils and groundwater at the site. In the fall of 1991, the EPA responded favorably to a request from the Company and other PRPs to participate in informal discussions on the EPA's ongoing investigation and evaluation of the site, and invited the Company and other interested parties to share technical information and resources with the EPA that might assist it in evaluating remedial options. Thereafter, the Company and other PRPs held several meetings with the EPA to discuss technical issues and received copies of the EPA's Supplemental Remedial Investigation Final Report, and its Baseline Risk Assessment Final Report.
On November 6, 1992, the EPA released its final RI/FS and announced a proposed remedy with an estimated total cost of approximately $49.5 million, including 30 years' operation and maintenance costs, with a net present value of approximately $26.4 million. The EPA's preferred remedy called for construction of a Containment/Disposal Facility "CDF" over a portion of the site. The CDF would have consisted of subsurface vertical barriers and a low permeability cap, with collection trenches and hydraulic control system to capture groundwater and prevent its migration outside of the CDF. Collected groundwater would have been treated and discharged or stored and disposed of off-site. The proposed remedy also would have required construction of new wetlands to replace those that would be destroyed by construction of the CDF and a long-term monitoring program.
On May 15, 1993, the PRP group in which the Company participated submitted extensive comments to the EPA opposing the proposed remedy. In response to an earlier request from the EPA, the PRP group also submitted a detailed analysis of an alternative remedy anticipated to cost approximately $20 million. In early June, in response to overwhelming negative comment, the EPA withdrew its proposed remedy and announced that it would work with all interested parties in developing a new proposal. Since then, the EPA has established a coordinating council, with representatives of PRPs, environmental groups, and government agencies, and presided over by a neutral mediator. The council is charged with determining what additional studies may be appropriate for the site and may also eventually address additional response activities. The Company is represented on the council.
In early 1994, the Company and other PRPs met with the EPA to commence negotiations on an Administration Order of Consent pursuant to which the PRPs would conduct additional studies agreed to by the coordinating council. Although negotiations are not yet complete, it is likely that the EPA will consent to allowing the PRPs to conduct additional studies at the site and that the EPA will not require reimbursement for its past RI/FS study costs as a condition to allowing the PRPs to conduct these additional studies. The EPA has previously advised the Company that ultimately it will seek to hold the Company and the PRPs liable for such costs.
In September 1991, the Company, New England Electric System and Vermont Gas Systems, Inc. entered into confidential negotiations with most other PRPs concerning allocation of unresolved liabilities concerning the site. Those negotiations are continuing.
In December 1991, the Company brought suit against several previous insurers seeking recovery of unrecovered past costs and indemnity against future liabilities associated with environmental problems at the site. The parties to this action are engaged in discovery and motions practice.
The Company has reached a confidential settlement with one of the defendants that provided the Company with second layer excess liability coverage for a seven month period in 1976. The Company has also reached a confidential agreement in principle with another insurance company defendant that provided the Company with comprehensive general liability insurance between 1976 and 1982, and with environmental impairment liability insurance from 1981 to 1984. These policies were in place in 1982 when the EPA first notified the Company that it might be a potentially responsible party at the Pine Street Marsh site.
The Company is unable to predict at this time the magnitude of any liability resulting from potential claims for the costs of the RI/FS or the performance of any remedial action, or the likely disposition or magnitude of claims the Company may have against others, including its insurers, except to the extent described above.
In its 1991 rate case, the Company, for the first time, sought recovery for expenses associated with the Pine Street Marsh site. Specifically, the Company proposed rate recognition of its estimated, unrecovered 1991 expenditures (approximately $400,000) for technical consultants and legal assistance in connection with the EPA's enforcement actions at the site and insurance litigation. While reserving the right to argue in the future about the appropriateness of rate recovery for Pine Street Marsh related costs, the Company and the Vermont Department of Public Service (Department) reached agreement that the full amount of Pine Street Marsh costs reflected in the Company's 1991 rate case should be recovered in rates. The Company's rates approved by the Vermont Public Service Board (VPSB) on April 2, 1992, reflected the 1991 Pine Street Marsh related expenditures referred to above.
In its rate increase request filed on October 1, 1993, the Company proposed rate recognition for its expenditures between January 1, 1992 and July 31, 1993 (approximately $4.2 million) for technical consultants and legal assistance in connection with the EPA's enforcement actions at the site and insurance litigation. The Department and the Company have reached the same agreement regarding recovery of these costs in rates that they reached with respect to the Company's 1991 Pine Street Marsh related expenditures. A comprehensive settlement of the Company's 1993 rate case, including the agreement regarding Pine Street Marsh costs, is currently pending before the VPSB.
As of December 31, 1993, the Company had reserved approximately $680,000 for costs attributable to the site, other than those costs that are the subject of the agreement between the Department and the Company mentioned above. Management expects to seek and receive ratemaking treatment for other costs incurred beyond the amounts that have been reserved. As of December 31, 1993, such other costs are approximately $4,918,000, which includes the $4.2 million in costs that are the subject of the rate case settlement agreement referred to above.
2. Operating Leases The Company has an operating lease for its corporate headquarters building and two of its service center buildings, including related real estate. This lease has a base term of 25 years, ending June 30, 2009, with renewal options aggregating another 25 years. The annual lease charges will total $983,000 for each of the years 1994 through 2008 and $574,000 for 2009. The Company has options to purchase the buildings at fair market value at the end of the base term and at the end of each renewal period.
3. Jointly-Owned Facilities The Company had joint-ownership interests in electric generating and transmission facilities at December 31, 1993, as follows:
Ownership Share of Utility Accumulated Interest Capacity Plant Depreciation (In %) (In MW) (In thousands) Highgate . . . . . . . . . . 33.8 67.6 $ 9,726 $2,310 McNeil . . . . . . . . . . . 11.0 5.9 $ 8,503 $2,464 Stony Brook (No. 1) . . . . . 8.8 30.2 $10,035 $4,660 Wyman (No. 4) . . . . . . . . 1.1 6.8 $ 2,372 $1,100 Metallic Neutral Return (1) . 59.4 --- $ 1,563 $ 181 (1)	Neutral conductor for NEPOOL/Hydro-Quebec Interconnection
The Company's share of expenses for these facilities is reflected in the Statements of Consolidated Income. Each participant in these facilities must provide for its own financing.
4. Rate Matters On October 1, 1993, the Company filed a request with the VPSB to increase retail rates by 8.6 percent. The increase is needed primarily to cover the cost of buying power from independent power producers, the cost of energy conservation programs, the cost of plant additions made in the last two years, and costs incurred in 1992 and through July 31, 1993, associated with the proposed remedy at the Pine Street Marsh site and with the Company's litigation against its previous insurers seeking recovery of past costs incurred and indemnity against future liabilities in connection with the site. On January 28, 1994, the parties to the rate proceeding reached an agreement resulting in a 2.9 percent retail rate increase and a return on equity of 10.5 percent, effective June 15, 1994. The agreement must be reviewed and approved by the VPSB.
5. Other Legal Matters The Company is involved in legal and administrative proceedings in the normal course of business and does not believe that the ultimate outcome of these proceedings will have a material effect on the financial position or the results of operations of the Company.
J. Obligations Under Transmission Interconnection Support Agreement Agreements executed in 1985 among the Company, VELCO and other NEPOOL members and Hydro-Quebec, provided for the construction of the second phase (Phase II) of the interconnection between the New England electric systems and that of Hydro-Quebec. Phase II expands the Phase I facilities from 690 megawatts to 2,000 megawatts and provides for transmission of Hydro-Quebec power from the Phase I terminal in northern New Hampshire to Sandy Pond, Massachusetts. Construction of Phase II commenced in 1988 and was completed in late 1990. The Company is entitled to 3.2 percent of the Phase II power-supply benefits. Total construction costs for Phase II were approximately $487 million. The New England participants, including the Company, have contracted to pay monthly their proportionate share of the total cost of constructing, owning and operating the Phase II facilities, including capital costs. As a supporting participant, the Company must make support payments under thirty-year agreements. These support agreements meet the capital lease accounting requirements under SFAS 13. At December 31, 1993, the present value of the Company's obligation is $11.0 million.
Projected future minimum payments under the Phase II support agreements are as follows: Year ending December 31, 1994 . . . . . . . . . . . $ 501,311 1995 . . . . . . . . . . . 501,311 1996 . . . . . . . . . . . 501,311 1997 . . . . . . . . . . . 501,311 1998 . . . . . . . . . . . 501,311 Total for 1999-2020 . . . 8,522,270 ----------- $11,028,825 ===========
The Phase II portion of the project is owned by New England Hydro- Transmission Electric Company and New England Hydro-Transmission Corporation, subsidiaries of New England Electric System, in which certain of the Phase II participating utilities, including the Company, own equity interests. The Company holds approximately 3.2 percent of the equity of the corporations owning the Phase II facilities.
K. Long-Term Power Purchases 1. Unit Purchases 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 "Power Supply Expenses" in the Statements of Consolidated Income.
Information (including estimates for the Company's portion of certain minimum costs and ascribed long-term debt) with regard to significant purchased power contracts of this type in effect during 1993 follows: Stony Vermont Merrimack Brook Yankee --------- ----- ------- (Dollars in thousands) Plant capacity . . . . . . . . . . . 320.0 MW 343.0 MW 520.0 MW Company's share of output . . . . . 8.9% 4.4% 17.3% Contract period . . . . . . . . . . 1968-1998 (1) (2) Company's annual share of: Interest . . . . . . . . . . . . . $ 589 $ 307 $ 1,403 Other debt service . . . . . . . . 297 270 --- Other capacity . . . . . . . . . . 1,560 353 26,327 ------ ------ ------- Total annual capacity . . . . . . . $2,446 $ 930 $27,730 ====== ====== ======= Company's share of long-term debt . $ 944 $5,983 $13,749 ====== ====== =======
(1) Life of plant estimated to be 1981 - 2006. (2) License for plant operations expires in 2012.
2. Hydro-Quebec System Power Purchases Under various contracts approved by the VPSB, the details of which are described in the table below, the Company purchases capacity and associated energy produced by the Hydro-Quebec system. Such contracts obligate the Company to pay certain fixed capacity costs whether or not energy purchases above a minimum level set forth in the contracts are made. Such minimum energy purchases must be made whether or not other, less expensive energy sources might be available. These contracts are intended to complement the other components in the Company's power supply to achieve the most economic power-supply mix reasonably available.
On October 12, 1990, the VPSB granted conditional approval of the Company's purchases pursuant to the contract with Hydro-Quebec entered into December 4, 1987: (1) Schedule A -- 17 megawatts of firm capacity and associated energy to be delivered at the Highgate interconnection for five years beginning 1990; (2) Schedule B -- 68 megawatts of firm capacity and associated energy to be delivered at the Highgate interconnection for twenty years beginning in September 1995; and (3) Schedule C3 -- 46 megawatts of firm capacity and associated energy to be delivered at interconnections to be determined at a later time for 20 years beginning in November 1995. The opponents to the December 1987 contract appealed the VPSB's October 1990 order to the Vermont Supreme Court. On October 2, 1992, the Vermont Supreme Court affirmed the VPSB's October 1990 order. On February 12, 1992, the VPSB issued an order finding that the Company had complied with substantial conditions imposed by the VPSB in its October 1990 order and approved the Company's purchase under the December 1987 contract. In March 1992, the opponents to the December 1987 contract appealed the VPSB's February 1992 compliance order to the Vermont Supreme Court. On May 7, 1993, the Vermont Supreme Court affirmed the VPSB's compliance order approving the Company's purchases under the December 1987 contract.
The Company anticipates that the Schedule C3 purchases will be delivered over its entitlement to the NEPOOL/Hydro-Quebec interconnection (Phase I and Phase II). If such interconnection is utilized, the Company must forego certain savings associated with other energy deliveries and capacity arrangements that would benefit the Company if the interconnection were not utilized for delivery of the Schedule C3 purchases. The Company believes that the benefits of the Schedule C3 purchases, if power is delivered over such interconnection, will offset the value of the foregone savings.
In September 1993, the Company negotiated a renewal of a short-term "tertiary energy" contract with Hydro-Quebec under which Hydro-Quebec delivers up to 61 megawatts of capacity and energy to the Company over the NEPOOL/Hydro-Quebec interconnection. The electricity purchased under this tertiary contract is priced at less than 2.5 cents per kilowatthour. The benefits realized by the Company from this favorably priced electricity will be greater than those associated with deliveries foregone by the Company otherwise available over the NEPOOL/Hydro-Quebec interconnection. This tertiary energy contract will expire in August 1994. The Company anticipates that purchases of tertiary energy will extend beyond August 1994, but will end when the Schedule C3 deliveries begin in November 1995.
On September 27, 1990, the Canadian National Energy Board (NEB) issued its decision approving the export by Hydro-Quebec pursuant to the December 1987 contract. The NEB, however, imposed a condition on its approval: Hydro-Quebec's export license was to be deemed valid so long as Hydro-Quebec obtained all federal and environmental approvals required for any of its new hydroelectric generating units advanced in order to satisfy Hydro-Quebec's contractual obligations. Hydro-Quebec and the Province of Quebec appealed the imposition of this condition to the Federal Court of Appeal. In a decision handed down on July 9, 1991, the Federal Court of Appeal agreed with Hydro-Quebec's assertion that the NEB has no authority to regulate the construction of hydroelectric generating units -- a matter that lies exclusively within provincial jurisdiction under the Canadian Constitution. The Federal Court of Appeal struck down the challenged NEB license condition and otherwise affirmed the license. The opponents to the December 1987 contract appealed the decision of the Federal Court of Appeal to the Supreme Court of Canada. On February 24, 1994, the Supreme Court of Canada rendered a decision reversing the judgment of the Federal Court of Appeal, and reinstated the NEB decision, including the condition that Hydro-Quebec had objected to.
The December 1987 contract, like the July 1984 contract, calls for the delivery of system power and is not related to any particular facilities in the Hydro-Quebec system. Consequently, there are no identifiable debt-service charges associated with any particular Hydro-Quebec facility that can be distinguished from the overall charges paid under the contract. Based on current integrated resource analyses, the Company believes that these contracts for Hydro-Quebec system power compare favorably with alternative long-term resources available to the Company.
July 1984 December 1987 Contract Contract Schedule A Schedule B Schedule C3 --------- ---------- ---------- ----------- 	(Dollars in thousands) Capacity Acquired . . . . 50 MW 17 MW 68 MW 46 MW Contract Period . . . . . 1985-1995 1990-1995 1995-2015 1995-2015 Minimum Energy Purchase (annual load factor) . 50% 50% 75% 75% (1992-1995)
Minimum Energy Charge . . $3,881 $2,134 $16,157 $11,060 (1993) (1993) (1995-2015)* (1995-2015)* $3,785 $2,281 (1994-1995)* (1994-1995) Annual Capacity Charge . $3,379 $1,681 $16,633 $11,821 (1993) (1993) (1995-2015)* (1995-2015)* $3,355 $1,691 (1994-1995)* (1994-1995)* Average Cost per KWH . . 2.8 cents 5.5 cents 7.0 cents 7.3 cents (1993) (1993) (1995-2015)** (1995-2015)** 2.7 cents 4.6 cents (1994-1995)* (1994-1995)*
*Estimated average. **Estimated average in nominal dollars, levelized over the period indicated.
3. Rochester Gas & Electric Purchase In 1988, the Company entered into a ten-year contract with Rochester Gas and Electric Corporation (RG&E) for the purchase of up to 50 megawatts of firm power and associated energy. This flexible contract allows the Company the discretion of purchasing from 0 megawatts to 50 megawatts on a weekly basis. The Company has no obligation to purchase power in any week. When the Company elects to schedule a purchase, however, it must take and pay for energy at a 75 percent load factor, or pay a penalty, in the week of the purchase. Although the Company has no fixed capacity payments, it must pay to reserve transmission from the Niagra Mohawk Power Corporation for the 50-megawatt maximum purchase. Both RG&E and the Company have the option to terminate the contract effective 1995.
Pursuant to an agreement with Connecticut Light and Power Corporation (CL&P) and Bozrah Light and Power (Bozrah) that was finalized in December 1992, the Company exercised the option to terminate the RG&E agreement and the transmission contract with Niagara Mohawk that supports it effective October 31, 1995. The Company also agreed to offer RG&E power to CL&P for purchase on a weekly basis through the remaining term of the RG&E agreement, and to terminate a contract under which the Company supplied all of the electrical requirements of Bozrah, a small electric utility operating in Gilman, Connecticut. In return, CL&P, which will replace the Company as the supplier of electricity to Bozrah, will assume responsibility for approximately 75 percent of the fixed costs of the transmission contract with Niagara Mohawk, and will provide the Company with up to 50 megawatts of system power, to be scheduled on a weekly basis, at a total price expected to be lower than that provided under the existing RG&E contract. In addition, CL&P has offered the Company an option, which may be exercised in yearly increments starting in July 1994, to purchase up to 50 additional megawatts of system power for the period July 1995 through December 2004.
The Company expects that the reductions in its purchased power and fixed transmission costs derived from this three-party agreement will more than offset the loss of revenues associated with the termination of its electricity sales contract with Bozrah. The arrangement was approved by FERC effective May 1, 1993.
Estimated Charges Annual Transmission Reservations . . . . . . . . . $300,000
Average Cost per KWH . . . . . . . . . . . . . . . (1993)(1) 4.1 cents (1994 - 1995)
(1)No power purchases were made under the RG&E or CL&P contracts described above during 1993.
REPORT OF INDEPENDENT PUBLIC ACCOUNTS
To the Board of Directors of Green Mountain Power Corporation:
We have audited the accompanying consolidated balance sheets and capitalization data of Green Mountain Power Corporation (a Vermont corporation) as of December 31, 1993 and 1992, and the related consolidated statements of income and cash flows for each of the three years in the period ended December 31, 1993. 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Green Mountain Power Corporation as of December 31, 1993 and 1992, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
As discussed in Notes A and G to the accompanying financial statements, effective January 1, 1993, the Company changed its method of accounting for post-retirement benefits other than pensions and income taxes.
ARTHUR ANDERSEN & CO.
Boston, Massachusetts February 1, 1994
Schedule V
GREEN MOUNTAIN POWER CORPORATION PROPERTY, PLANT AND EQUIPMENT December 31, 1993
Schedule V
GREEN MOUNTAIN POWER CORPORATION PROPERTY, PLANT AND EQUIPMENT December 31, 1992
Schedule V
GREEN MOUNTAIN POWER CORPORATION PROPERTY, PLANT AND EQUIPMENT December 31, 1991
Schedule VI GREEN MOUNTAIN POWER CORPORATION ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT For the Years Ended December 31, 1993, 1992 and 1991
Schedule VIII GREEN MOUNTAIN POWER CORPORATION VALUATION AND QUALIFYING ACCOUNTS AND RESERVES For the Years Ended December 31, 1993, 1992 and 1991
Schedule IX
GREEN MOUNTAIN POWER CORPORATION Short-term Borrowings For the Years Ended December 31, 1993, 1992 and 1991
Schedule X GREEN MOUNTAIN POWER CORPORATION Supplementary Income Statement Information For the Years Ended December 31, 1993, 1992 and 1991
All other items were not material or were disclosed in the Consolidated Financial Statements or the related notes.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
ITEMS 10, 11, 12 & 13
Certain information regarding executive officers called for by Item 10, "Directors and Executive Officers of the Registrant," is furnished under the caption, "Executive Officers" in Item 1 of Part I of this Report. The other information called for by Item 10, as well as that called for by Items 11, 12, and 13, "Executive Compensation," "Security Ownership of Certain Beneficial Owners and Management" and "Certain Relationships and Related Transactions," will be set forth under the captions "Nominees for Director," "Compliance with the Securities Exchange Act," "Executive Compensation," "Pension Plan Information" and "Security Ownership of Certain Beneficial Owners and Management" in the Company's definitive proxy statement relating to its annual meeting of stockholders to be held on May 19, 1994. Such information is incorporated herein by reference. Such proxy statement pertains to the election of directors and other matters. Definitive proxy materials will be filed with the Securities and Exchange Commission pursuant to Regulation 14A in April 1994.
PART IV
ITEM 14.







ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
Filed Herewith On Page
Item 14(a)(1). The financial statements and financial 38 statement schedules of the Company are listed on the Index to financial statements set forth in Item 8 hereof.
Item 14(a)(2). The financial statements and financial 84 statement schedules of Vermont Yankee Nuclear Power Corporation, together with report thereon of Arthur Andersen & Co. and KPMG Peat Marwick are bound and filed herewith as Item 14(d).
ITEM 14(a)(3). EXHIBITS
____________________ * Filed herewith
ITEM 14(b)	
	There were no reports on Form 8-K filed for the quarter ending December 31, 1993.
OTHER MATTERS
	For the purposes of complying with the amendments to the rules governing Form S-8 (effective July 13, 1990) under the Securities Act of 1933, the undersigned registrant hereby undertakes as follows, which undertaking shall be incorporated by reference into registrant's Registration Statement on Form S-8 No. 33-47985 (filed May 14, 1992):
	Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
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.
GREEN MOUNTAIN POWER CORPORATION
By: /s/D. G. Hyde Date: March 31, 1994 ---------------------------- 	(D. G. Hyde, President and 	Chief Executive Officer)
	Pursuant to the requriements 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.
SIGNATURE TITLE DATE
/s/D. G. Hyde Chairman of the Executive Commit- March 31, 1994 (D. G. Hyde) tee, President, Chief Executive Officer and Director
/s/E. M. Norse Vice President, Treasurer and March 31, 1994 (E. M. Norse) Chief Financial Officer (Principal Financial Officer)
/s/G. J. Purcell Controller March 31, 1994 (G. J. Purcell) (Principal Accounting Officer)
/s/T. P. Salmon Chairman of the Board and March 31, 1994 (T. P. Salmon) Director
/s/R. E. Boardman Director March 31, 1994 (R. E. Boardman)
/s/N. L. Brue Director March 31, 1994 (N. L. Brue)
/s/W. H. Bruett Director March 31, 1994 (W. H. Bruett)
/s/M. O. Burns Director March 31, 1994 (M. O. Burns)
/s/J. V. Cleary Director March 31, 1994 (J. V. Cleary)
/s/R. I. Fricke Director March 31, 1994 (R. I. Fricke)
/s/E. A. Irving Director March 31, 1994 (E. A. Irving)
/s/M. L. Johnson Director March 31, 1994 (M. L. Johnson)
/s/R. W. Page Director March 31, 1994 (R. W. Page)
ITEM 14(d) FINANCIAL STATEMENTS
VERMONT YANKEE NUCLEAR POWER CORPORATION
FINANCIAL STATEMENTS
December 31, 1993, 1992 and 1991
(WITH INDEPENDENT AUDITOR'S REPORT THEREON)
VERMONT YANKEE NUCLEAR POWER CORPORATION
Index to Financial Statements and Financial Statement Schedules
Financial Statements: Page
Balance Sheets, December 31, 1993 and 1992 88-89
Statements of Income and Retained Earnings, years ended December 31, 1993, 1992 and 1991 90
Statements of Cash Flows, years ended December 31, 1993, 1992 and 1991 91
Notes to Financial Statements 92-105
Financial Statements:
Schedule I - Marketable Securities and Other Investments at December 31, 1993 106
Schedule V - Property, Plant and Equipment, years ended December 31, 1993, 1992 and 1991 107
Schedule VI - Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment, years ended December 31, 1993, 108 1992 and 1991
All other schedules are omitted as the required information is inapplicable or the required information is included in the financial statements or related notes.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
The Stockholders and Board of Directors of Vermont Yankee Nuclear Power Corporation:
We have audited the accompanying balance sheet of Vermont Yankee Nuclear Power Corporation as of December 31, 1993, and the related statements of income and retained earnings and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of Vermont Yankee Nuclear Power Corporation as of December 31, 1992 and 1991, were audited by other auditors whose report, dated February 5, 1993, expressed an unqualified opinion on those statements and included an additional paragraph discussing the Company's 1992 change in accounting for postretirement benefits other than pensions.
We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Vermont Yankee Nuclear Power Corporation as of December 31, 1993, and the results of its operations and its cash flows for the year then ended, in conformity with generally accepted accounting principles.
As discussed in Note 10 to the accompanying financial statements, effective January 1, 1993, the Company adopted the provisions of Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes.
Our audit was made for the purpose of forming an opinion on the basic financial statements taken as whole. Supplementary schedules I, V and VI are presented for purposes of additional analysis and are not a required part of the basic financial statements. This information has been subjected to the auditing procedures applied in our audit of the basic financial statements and, in our opinion, is fairly stated in, all material respects, in relation to the basic financial statements taken as a whole.
Boston, Massachusetts January 27, 1994 ARTHUR ANDERSEN & CO.
INDEPENDENT AUDITORS' REPORT
The Stockholders and Board of Directors Vermont Yankee Nuclear Power Corporation:
We have audited the balance sheet of Vermont Yankee Nuclear Power Corporation as of December 31, 1992, and the related statements of income and retained earnings and cash flows for each of the years in the two-year period ended December 1992. In connection with our audits of the financial statements, we also have audited the financial statement schedules for each of the years in the two-year period ended December 31, 1992. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules 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 Vermont Yankee Nuclear Power Corporation at December 31, 1992 and the results of its operations and cash flows for each of the years in the two-year period ended December 31, 1992, in conformity with generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
As discussed in note 13, the Company adopted the provisions of Statement of Financial Accounting Standards Number 106, Employers' Accounting for Postretirement Benefits Other than Pensions, in 1992.
KPMG Peat Marwick
Boston, Massachusetts February 5, 1993
Balance Sheets Assets December 31, ------------ 1993 1992 ---- ---- (Dollars in thousands) Utility plant: Electric plant, at cost (note 6) $ 374,736 $ 362,278 Less accumulated depreciation 198,389 185,263 ________ ________ 176,347 177,015 Construction work in progress 597 6,408 ________ ________ Net electric plant 176,944 183,423 ________ ________ Nuclear fuel, at cost (note 6): Assemblies in reactor 69,063 74,025 Fuel in process --- 5,236 Spent fuel 287,700 259,199 ________ ________ 356,763 338,460 Less accumulated amortization of burned nuclear fuel 317,039 302,362 ________ ________ 39,724 36,098 Less accumulated amortization of final core nuclear fuel 7,220 6,487 ________ ________ Net nuclear fuel 32,504 29,611 ________ ________ Net utility plant 209,448 213,034 ________ ________ Current assets: Cash and temporary investments 2,349 1,922 Accounts receivable from sponsors 12,235 15,407 Other accounts receivable 4,522 2,715 Materials and supplies 17,081 16,862 Prepaid expenses 3,949 4,381 ________ ________ Total current assets 40,136 41,287 ________ ________ Deferred charges: Deferred decommissioning costs (note 2) 34,379 34,389 Accumulated deferred income taxes (note 10) 18,231 10,378 Deferred DOE enrichment site decontamination and decommissioning fee (note 4) 18,627 18,143 Net unamortized loss on reacquired debt 2,942 --- Other deferred charges (note 4) 3,643 4,994 ________ ________ Total deferred charges 77,822 67,904 ________ ________ Long-term funds at amortized cost: Decommissioning fund (notes 2, 5, and 7) 98,880 82,091 Disposal fee defeasance fund (notes 5, 7, and 8) 43,484 33,892 ________ ________ Total long-term funds 142,364 115,983 ________ ________ $469,770 $438,208 ======== ======== See accompanying notes to financial statements.
Balance Sheets Capitalization and Liabilities December 31, ------------ 1993 1992 ---- ---- (Dollars in thousands) Capitalization: Common stock equity: Common stock, $100 par value; authorized 400,100 shares; issued 400,014 shares of which 7,533 are held in Treasury $ 40,001 $ 40,001 Additional paid-in capital 14,227 14,227 Treasury stock (7,533 shares at cost) (1,131) (1,131) Retained earnings 1,067 1,178 ________ ________ Total common stock equity 54,164 54,275 ________ ________ Long-term obligations, net (notes 6 and 7) 79,636 74,193 ________ ________ Total capitalization 133,800 128,468 ________ ________ Commitments and contingencies (notes 2, 14 and 15)
Disposal fee and accrued interest for spent nuclear fuel (notes 7 and 8) 80,688 78,239 ________ ________ Current liabilities: Accrued liabilities 28,063 22,743 Accounts payable 2,117 2,591 Accrued interest 635 974 Accrued taxes 1,206 1,472 ________ ________ Total current liabilities 32,021 27,780 ________ ________ Deferred credits: Accrued decommissioning costs (note 2) 134,614 117,601 Accumulated deferred income taxes 56,478 58,963 Net regulatory tax liability (note 10) 8,351 --- Accumulated deferred investment tax credits 7,013 7,590 Net unamortized gain on reacquired debt --- 1,732 Accrued DOE enrichment site decon- tamination and decommissioning fee (note 4) 15,966 17,220 Other deferred credits 839 615 ________ ________ Total deferred credits 223,261 203,721 ________ ________ $469,770 $438,208 ======== ========
See accompanying notes to financial statements.
Statements of Income and Retained Earnings Years ended December 31, ------------------------ 1993 1992 1991 ---- ---- ---- (Dollars in thousands except per share amounts)
Operating revenues $180,145 $175,919 $151,722 ________ ________ ________ Operating expenses: Nuclear fuel expense 19,526 21,240 24,864 Other operating expense 74,013 72,967 59,666 Maintenance 31,405 27,878 13,664 Depreciation 13,707 13,253 11,800 Decommissioning expense (note 2) 11,315 10,649 8,065 Taxes on income (note 10) 3,777 3,401 3,485 Property and other taxes 9,961 10,227 10,294 ________ ________ ________ Total operating expenses 163,704 159,615 131,838 ________ ________ ________ Operating income 16,441 16,304 19,884 ________ ________ ________ Other income and (deductions): Net earnings on decommissioning fund (notes 2 and 5) 5,653 5,395 4,423 Decommissioning expense (note 2) (5,653) (5,395) (4,423) Allowance for equity funds used during construction 92 89 124 Interest 1,550 2,046 1,377 Taxes on other income (note 10) (623) (756) (447) Other, net (232) (199) (917) ________ ________ ________ 787 1,180 137 ________ ________ ________ Income before interest expense 17,228 17,484 20,021 ________ ________ ________ Interest expense: Interest on long-term debt 7,281 7,101 7,684 Interest on disposal costs of spent nuclear fuel (note 8) 2,450 2,801 4,312 Allowance for borrowed funds used during construction (297) (339) (465) ________ ________ ________ Total interest expense 9,434 9,563 11,531 ________ ________ ________ Net income 7,794 7,921 8,490 Retained earnings at beginning of year 1,178 1,166 1,982 ________ ________ ________ 8,972 9,087 10,472 Dividends declared 7,905 7,909 9,306 ________ ________ ________ Retained earnings at end of year $ 1,067 $ 1,178 $ 1,166 ======== ======== ======== Average number of shares outstanding in thousands 392 392 394 ======== ======== ======== Net income per average share of common stock outstanding $ 19.86 $ 20.18 $ 21.56 ======== ======== ======== Dividends per average share of common stock outstanding $ 20.14 $ 20.15 $ 23.71 ======== ======== ======== See accompanying notes to financial statements.
Statements of Cash Flows Years ended December 31, ------------------------ 1993 1992 1991 ---- ---- ---- (Dollars in thousands) Cash flows from operating activities: Net income $ 7,794 $ 7,921 $ 8,490 ________ ________ ________ Adjustments to reconcile net income to net cash provided by operating activities: Amortization of nuclear fuel 15,410 18,143 21,002 Depreciation 13,707 13,253 11,800 Decommissioning expense 11,315 10,649 8,065 Deferred tax expense (979) (2,169) (801) Amortization of deferred investment tax credit (577) (641) (740) Nuclear fuel disposal fee interest accrual 2,450 2,802 4,312 Interest and dividends on disposal fee defeasance fund (1,402) (1,385) (1,495) (Increase) decrease in accounts receivable 1,365 688 (129) (Increase) decrease in prepaid expenses 432 (1,159) 163 (Increase) in materials and supplies inventory (219) (454) (1,531) Increase (decrease) in accounts payable and accrued liabilities 4,846 (7,453) 5,495 Increase (decrease) in interest and taxes payable (605) 306 (760) Other (1,228) (1,410) (1,665) ________ ________ ________ Total adjustments 44,515 31,170 43,716 ________ ________ ________ Net cash provided by operating activities 52,309 39,091 52,206 ________ ________ ________ Cash flows from investing activities: Electric plant additions (7,229) (10,750) (6,596) Nuclear fuel additions (18,303) (4,707) (18,444) Payments to decommissioning fund (11,250) (10,612) (8,323) Payments to disposal fee defeasance fund (8,190) (5,190) (8,216) ________ ________ ________ Net cash used in investing activities (44,972) (31,259) (41,579) ________ ________ ________ Cash flows from financing activities: Dividend payments (7,905) (7,909) (9,306) Purchase of treasury stock --- --- (1,131) Issuance of Series H first mortgage bonds, net --- --- 10,374 Issuance of Series I first mortgage bonds, net 75,125 --- --- Retirement of first mortgage bonds including redemption costs (74,629) (6,521) (13,178) Payments of long-term obligations (137,911) (107,763) (53,419) Borrowings under long-term agreements 138,410 111,215 53,798 ________ ________ ________ Net cash used in financing activities (6,910) (10,978) (12,862) ________ ________ ________ Net increase (decrease) in cash and temporary investments 427 (3,146) (2,235) Cash and temporary investments at beginning of year 1,922 5,068 7,303 ________ ________ ________ Cash and temporary investments at end of year $ 2,349 $ 1,922 $ 5,068 ======== ======== ======== See accompanying notes to financial statements.
Notes to Financial Statements
NOTE 1. Summary of Significant Accounting Policies
(a) Regulations and Operations
Vermont Yankee Nuclear Power Corporation ("the Company") is subject to regulations prescribed by the Federal Energy Regulatory Commission ("FERC"), and the Public Service Board of the State of Vermont with respect to accounting and other matters. The Company is also subject to regulation by the Nuclear Regulatory Commission ("NRC") for nuclear plant licensing and safety, and by federal and state agencies for environmental matters such as air quality, water quality and land use.
Prior to November, 1993, the Company was subject to regulation by the Securities and Exchange Commission. As a result of the debt refinancing discussed in note 6, the Company is no longer subject to such regulation.
The Company recognizes revenue pursuant to the terms of the Power Contracts and Additional Power Contracts. The Sponsors, a group of nine New England utilities, are severally obligated to pay the Company each month their entitlement percentage of amounts equal to the Company's total fuel costs and operating expenses of its Plant, plus an allowed return on equity (since December 1, 1989, 12.25%). Such contracts also obligate the Sponsors to make decommissioning payments through the end of the Plant's service life and the completion of the decommissioning of the Plant. All Sponsors are committed to such payments regardless of the Plant's operating level or whether the Plant is out of service during the period.
Under the terms of the Capital Funds Agreements, the Sponsors are committed, subject to obtaining necessary regulatory authorizations, to make funds available to obtain or maintain licenses necessary to keep the Plant in operation.
(b) Depreciation and Maintenance
Electric plant is being depreciated on the straight-line method at rates designed to fully depreciate all depreciable properties over the lesser of estimated useful lives or the Plant's remaining NRC license life, which extends to March, 2012. Depreciation expense was equivalent to overall effective rates of 3.74%, 3.56% and 3.23% for the years 1993, 1992 and 1991, respectively.
Renewals and betterments constituting retirement units are charged to electric plant. Minor renewals and betterments are charged to maintenance expense. When properties are retired, the original cost, plus cost of removal, less salvage, is charged to the accumulated provision for depreciation.
(c) Amortization of Nuclear Fuel
The cost of nuclear fuel is amortized to expense based on the rate of burn-up of the individual assemblies comprising the total core. The Company also provides for the costs of disposing of spent nuclear fuel at rates specified by the United States Department of Energy ("DOE") under a contract for disposal between the Company and the DOE.
The Company amortizes to expense on a straight-line basis the estimated costs of the final unspent nuclear fuel core, which is expected to be in place at the expiration of the Plant's NRC operating license in conformity with rates authorized by the FERC.
(d) Amortization of Materials and Supplies
The Company amortizes to expense a formula amount designed to fully amortize the cost of the material and supplies inventory that is expected to be on hand at the expiration of the Plant's NRC operating license.
(e) Long-term Funds
The Company accounts for its investments in long-term funds at amortized cost since it has both the intent and ability to hold these investments for the foreseeable future. Amortized cost represents the cost to purchase the investment, net of any unamortized premiums or discounts.
(f) Amortization of Gain and Loss on Reacquired Debt
The difference between the amount paid upon reacquisition of any debt security and the face value thereof, plus any unamortized premium, less any related unamortized debt expense and reacquisition costs, or less any unamortized discount, related unamortized debt expense and reacquisition costs applicable to the debt redeemed, retired and canceled, is deferred by the Company and amortized to expense on a straight-line basis over the remaining life of the applicable security issues.
(g) Allowance for Funds Used During Construction
Allowance for funds used during construction ("AFUDC") is the estimated cost of funds used to finance the Company's construction work in progress and nuclear fuel in process which is not recovered from the Sponsors through current revenues. The allowance is not realized in cash currently, but under the Power Contracts, the allowance will be recovered in cash over the Plant's service life through higher revenues associated with higher depreciation and amortization expense.
AFUDC was capitalized at overall effective rates of 5.92%, 6.82% and 6.98% for 1993, 1992 and 1991, respectively, using the gross rate method.
(h) Decommissioning
The Company is accruing the estimated costs of decommissioning its Plant over the Plant's remaining NRC license life. Any amendments to these estimated costs are accounted for prospectively.
(i) Taxes on Income
Effective January 1, 1993, the Company began accounting for taxes on income under the liability method required by Statement of Financial Accounting Standard 109. See Note 10 for a further discussion of this change in accounting.
Investment tax credits have been deferred and are being amortized to income over the lives of the related assets.
(j) Cash Equivalents
For purposes of the Statements of Cash Flows, the Company considers all highly liquid short-term investments with an original maturity of three months or less to be cash equivalents.
(k) Reclassifications
Certain information in the 1992 and 1991 financial statements has been reclassified to conform with the 1993 presentation.
(l) Earnings per Common Share
Earnings per common share have been computed by dividing earnings available to common stock by the weighted average number of shares outstanding during the year.
NOTE 2. Decommissioning
The Company accrues estimated decommissioning costs for its nuclear plant over its remaining NRC licensed life based on studies by an independent engineering firm that assumes that decommissioning will be accomplished by the prompt removal and dismantling method. This method requires that radioactive materials be removed from the plant site and that all buildings and facilities be dismantled immediately after shutdown. Studies estimate that approximately six years would be required to dismantle the Plant at shutdown, remove wastes and restore the site. The Company has implemented rates based on a settlement agreement with the FERC which allowed $190 million, in 1988 dollars, as the estimated decommissioning cost. This allowed amount is used to compute the Company's liability and billings to the Sponsors. Based on an assumed inflation rate of 6% per annum and an expiration of the Plant's NRC operating license in 2012, the estimated current cost of decommissioning is $253 million and, at the end of 2012, is approximately $769 million. The present value of the pro rata portion of decommissioning costs recorded to date is $134.6 million. On December 31, 1993, the balance in the Decommissioning Trust was $98.9 million.
Billings to Sponsors for estimated decommissioning costs commenced during 1983, at which time the Company recorded a deferred charge for the present value of decommissioning costs applicable to operations of the Plant for prior periods. Current period decommissioning costs not funded through billings to Sponsors or earnings on decommissioning fund assets are also deferred. These deferred costs will be amortized to expense as they are funded over the remaining life of the NRC operating license.
In 1994, the Company must file a revised estimate of decommissioning costs and a revised schedule of future annual decommissioning fund collections reflecting the historical differences between assumed and actual rates of inflation and the historical differences between assumed and actual rates of earnings on decommissioning fund assets. Filings are required to be made within four years of the most recent FERC approval of decommissioning cost estimates and rates.
Cash received from Sponsors for plant decommissioning costs is deposited into the Vermont Yankee Decommissioning Trust in either the Qualified Fund (i.e., amounts currently deductible pursuant to the IRS regulations) or the Nonqualified Fund (i.e., excess collections pursuant to FERC authorization which are not currently deductible). Funds held by the Trust are invested in high-grade U.S. government securities and municipal obligations. Interest earned by the Decommissioning Trust assets is recorded in other income and deductions, with an equal and offsetting amount representing the current period decommissioning cost funded by such earnings reflected as decommissioning expense.
Decommissioning expense for 1991 included an adjustment of approximately $2.1 million resulting from the Company's rate reduction filing approved by the FERC on February 28, 1991 as discussed in Note 3.
NOTE 3. FERC Rate Case Matters
On April 27, 1989, Vermont Yankee filed an application with the NRC to extend the term of the operating license from 2007 to 2012 so that the Plant may operate for 40 years after it entered commercial service in 1972. On December 17, 1990, the NRC issued an amendment to the operating license extending its term to March 21, 2012. The Company submitted a rate reduction filing with the FERC to reflect in rates the adjustments to decommissioning, depreciation and amortization resulting from the license extension. The Company proposed to make this reduction effective as of March 1, 1991 and, since the extension was issued in 1990, to reflect the necessary adjustment for the period January 1, 1990 through February 28, 1991.
On February 28, 1991, the FERC approved the Company's rate reduction filing. The effects of this ruling were accounted for prospectively in fiscal 1991, producing a net revenue reduction ofapproximately $7.4 million in 1991, which reflected the retroactive treatment to January 1, 1990. This ruling resulted in reduced revenue requirements of approximately $3.5 million for both 1992 and 1993, and similar reductions are expected in future years.
On March 26, 1993, the FERC initiated a review of the return on common equity component of the formula rates included in the Company's Power Contracts. On October 22, 1993, the FERC approved a settlement whereby the Company retained its 12.25% authorized rate of return on common equity and agreed to credit monthly power billings by approximately $139,000 beginning in June, 1993.
In 1994, the Company will submit a rate filing to the FERC which will include, among other things, a revised estimate of decommissioning costs and a revised schedule of future annual decommissioning fund collections.
NOTE 4. Other Deferred Charges and Credits
In October, 1992, Congress passed the Energy Policy Act of 1992 which requires, among other things, that certain utilities help pay for the cleanup of the DOE's enrichment facilities over a 15- year period. The Company's annual fee is estimated based on the historical share of enrichment service provided by the DOE and is indexed to inflation. These fees will not be adjusted for future business as the DOE's future cost of sales will include a decontamination and decommissioning component. The Act stipulates that the annual fee shall be fully recoverable in rates in the same manner as other fuel costs.
In 1993, the DOE billed and the Company paid the first of the 15 annual fees. As of December 31, 1993, the Company has recognized a current accrued liability of $2.6 million for the two fee payments expected to be made in 1994, a deferred credit of $16.0 million for the 12 annual fee payments that are due subsequent to 1994 and a corresponding regulatory asset of $18.6 million which represents the total amount includable in future billings to the purchasers under the Power Contracts. While these amounts are reflected in these financial statements, the Company is reviewing the DOE's calculation of the annual fee and believes that the annual fee will ultimately be reduced.
Approximately $2.1 and $3.3 million of the $3.6 and $5.0 million in other deferred charges at December 31, 1993 and 1992, respectively, relate to payments made to the Vermont Low Level Radioactive Waste Authority ("VLLRWA"), an agency of the State of Vermont for the siting and construction of a low-level waste disposal facility.
NOTE 5. Long-term Funds
The book value and estimated market value of long-term fund investment securities at December 31, is as follows:
At December 31, 1993 and 1992, gross unrealized gains and losses pertaining to the long-term investment securities were as follows:
1993 1992 ---- ---- (Dollars in thousands) Unrealized gains on U.S. Treasury obligations $ 1,431 $ 1,071 ------- ------- Unrealized losses on U.S. Treasury obligations $ (27) $ (4) ------- ------- Unrealized gains on Municipal obligations $ 4,843 $ 1,895 ------- ------- Unrealized losses on Municipal obligations $ (22) $ (27) ------- ------- Unrealized losses on corporate bonds and notes $ (112) $ (170) ------- -------
Maturities of short-term obligations, bonds and notes (face amount) at December 31, 1993 are as follows (dollars in thousands):
Within one year $ 42,200 Two to five years 16,977 Five to seven years 19,670 Over seven years 57,860 _______ $136,707 =======
NOTE 6. Long-term Obligations
A summary of long-term obligations at December 31, 1993 and 1992 is as follows:
1993 1992 ---- ---- (Dollars in thousands) First mortgage bonds: Series B - 8.50% due 1998 $ --- $ 1,307 Series C - 7.70% due 1998 --- 1,612 Series D - 10.125% due 2007 --- 23,147 Series E - 9.875% due 2007 --- 5,703 Series F - 9.375% due 2007 --- 5,704 Series G - 8.94% due 1995 --- 25,000 Series H - 8.25% due 1996 --- 8,388 Series I - 6.48% due 2009 75,845 --- ______ ______ Total first mortgage bonds 75,845 70,861
Eurodollar Agreement Commercial Paper 3,791 3,292
Unamortized premium on debt --- 40 ______ ______ Total long-term obligations $79,636 $74,193 ====== ======
The first mortgage bonds are issued under, have the terms and provisions set forth in, and are secured by an Indenture of Mortgage dated as of October 1, 1970 between the Company and the Trustee, as modified and supplemented by 13 supplemental indentures. All bonds are secured by a first lien on utility plant, exclusive of nuclear fuel, and a pledge of the Power Contracts and the Additional Power Contracts (except for fuel payments) and the Capital Funds Agreements with Sponsors.
On July 1, 1993, the Company retired the outstanding Series B and Series C first mortgage bonds. In November, 1993, the Company issued $75.8 million of Series I, first mortgage bonds stated to mature on November 1, 2009. The Company applied the proceeds of the bond issuance principally to retire the remaining Series D, Series E, Series F, Series G and Series H first mortgage bonds including call premiums totalling $3.7 million based on the early redemption of the bonds. Cash sinking fund requirements for the Series I first mortgage bonds are $5.4 million annually beginning in November, 1999.
The Company has a $75.0 million Eurodollar Credit Agreement that expires on December 31, 1995 subject to three optional one-year extensions. The Company issued commercial paper under this agreement with weighted average interest rates of 3.22% for 1993 and 3.95% for 1992. Payment of the commercial paper is supported by the Eurodollar Credit Agreement, which is secured by a second mortgage on the Company's generating facility.
NOTE 7. Disclosures About the Fair Value of Financial Instruments
The carrying amounts for cash and temporary investments, trade receivables, accounts receivable from sponsors, accounts payable and accrued liabilities approximate their fair values because of the short maturity of these instruments. The fair values of long-term funds are estimated based on quoted market prices for these or similar investments. The fair values of each of the Company's long-term debt instruments are estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities.
The estimated fair value of the Company's financial instruments as of December 31 are summarized as follows (dollars in thousands):
1993 1992 ---- ---- Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value -------- ---------- -------- ----------
Decommissioning fund $98,880 $105,105 $82,091 $85,026 Disposal fee defeasance fund 43,484 43,372 33,892 33,722 Long-term debt 79,636 77,361 74,193 78,235 Disposal fee and accrued interest 80,688 80,688 78,239 78,239
Fair value estimates are made at a specific point in time, based on relevant market information and information about the financial instrument. These estimates are subjective in nature and involve uncertainties and matters of significant judgment and therefore cannot be determined with precision. Changes in assumptions could significantly affect the estimates.
NOTE 8. Disposal Fee for Spent Nuclear Fuel
The Company has a contract with the United States Department of Energy ("DOE") for the permanent disposal of spent nuclear fuel. Under the terms of this contract, in exchange for the one-time fee discussed below and a quarterly fee of 1 mil per kwh of electricity generated and sold, the DOE agrees to provide disposal services when a facility for spent nuclear fuel and other high-level radioactive waste is available, which is required by current statute to be prior to January 31, 1998.
The DOE contract obligates the Company to pay a one-time fee of approximately $39.3 million for disposal costs for all spent fuel discharged through April 7, 1983. Although such amount has been collected in rates from the Sponsors, the Company has elected to defer payment of the fee to the DOE as permitted by the DOE contract. The fee must be paid no later than the first delivery of spent nuclear fuel to the DOE. Interest accrues on the unpaid obligation based on the thirteen-week Treasury Bill rate and is compounded quarterly. Through 1993, the Company deposited approximately $37.5 in an irrevocable trust to be used exclusively for defeasing this obligation at some future date, provided the DOE complies with the terms of the aforementioned contract.
On December 31, 1991, the DOE issued an amended final rule modifying the Standard Contract for Disposal of Spent Nuclear Fuel and/or High-level Radioactive Waste. The amended final rule conforms with a March 17, 1989 ruling of the U.S. Court of Appeals for the District of Columbia that the 1 mil per kilowatt hour fee in the Standard Contract should be based on net electricity generated and sold. The impact of the amendment on the Company was to reduce the basis for the fee by 6% on an ongoing basis and to establish a receivable from the DOE for previous overbillings and accrued interest. The Company has recognized in its rates the full impact of the amended final rule to the Standard Contract.
The DOE is refunding the overpayments, including interest, to utilities over a four-year period ending in 1995 via credits against quarterly payments. Interest is based on the 90-day Treasury Bill Auction Bond Equivalent and will continue to accrue on amounts remaining to be credited. At December 31, 1993 and 1992, respectively, approximately $0.9 and $1.6 million in principal and interest is reflected in other accounts receivable.
NOTE 9. Short-term Borrowings
The Company had lines of credit from various banks totalling $6.3 million at December 31, 1993 and 1992. The maximum amount of short-term borrowings outstanding at any month-end during 1993, 1992 and 1991 was approximately $0.2 million, $0.6 million and $0.4 million, respectively. The average daily amount of short-term borrowings outstanding was approximately $0.3 million for 1993, and $0.1 million for 1992 and 1991 with weighted average interest rates of 5.75% in 1993, 6.12 % in 1992 and 8.19% in 1991. There were no amounts outstanding under these lines of credit as of December 31, 1993 and 1992.
NOTE 10. Taxes on Income
In February, 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes", which required the Company to change from the deferred method to the liability method of accounting for income taxes on January 1, 1993. The liability method accounts for deferred income taxes by applying enacted statutory rates in effect at the balance sheet date to differences between the book basis and the tax basis of assets and liabilities ("temporary differences").
This new statement requires recognition of deferred tax liabilities for (a) income tax benefits associated with timing differences previously passed on to customers and (b) the equity component of allowance for funds used during construction, and of a deferred tax asset for the tax effect of the accumulated deferred investment tax credits. It also requires the adjustment of deferred tax liabilities or assets for an enacted change in tax laws or rates, among other things.
Although adoption of this new statement has not and is not expected to have a material impact on the Company's cash flow, results of operations or financial position because of the effect of rate regulation, the Company was required to recognize an adjustment to accumulated deferred income taxes and a corresponding regulatory asset or liability to customers (in amounts equal to the required deferred income tax adjustment) to reflect the future revenues or reduction in revenues that will be required when the temporary differences turn around and are recovered or settled in rates. In addition, this new statement required a reclassification of certain deferred income tax liabilities to liabilities to customers in order to reflect the Company's obligation to flow back deferred income taxes provided at rates higher than the current 35% federal tax rate. The Company has applied the provisions of this new statement without restating prior year financial statements.
The components of income tax expense for the years ended December 31, 1993, 1992 and 1991 are as follows:
1993 1992 1991 ---- ---- ---- (Dollars in thousands)
Taxes on operating income: Current federal income tax $ 4,236 $ 4,926 $ 4,003 Deferred federal income tax (1,059) (1,840) (1,285) Current state income tax 1,097 1,285 1,024 Deferred state income tax 80 (329) 483 Investment tax credit adjustment (577) (641) (740) ______ ______ ______ 3,777 3,401 3,485 ______ ______ ______ Taxes on other income: Current federal income tax 496 598 353 Current state income tax 127 158 94 ______ ______ ______ 623 756 447 ______ ______ ______ Total income taxes $ 4,400 $ 4,157 $ 3,932 ====== ====== ======
A reconciliation of the Company's effective income tax rates with the federal statutory rate is as follows:
1993 1992 1991 ---- ---- ---- Federal statutory rate 35.0% 34.0% 34.0% State income taxes, net of federal income tax benefit 6.9 6.1 6.1 Investment credit (4.7) (5.3) (6.0) Book depreciation in excess of tax basis 2.0 1.9 1.7 AFUDC equity 0.6 0.9 0.9 Flowback of excess deferred taxes (3.6) (3.1) (6.7) Other (0.1) (0.1) 1.7 ____ ____ ____ 36.1% 34.4% 31.7% ==== ==== ====
The items comprising deferred income tax expense are as follows:
1993 1992 1991 ---- ---- ---- (Dollars in thousands)
Decommissioning expense not currently deductible $ (351) $ (104) $ 14 Tax depreciation over (under) financial statement depreciation (978) (679) 955 Tax fuel amortization over (under) financial statement amortization (255) (637) (1,389) Tax loss on reacquisition of debt over (under) financial statement expense 1,887 187 178 Pension expense not currently deductible (167) (192) (562) Postemployment benefits deduction over (under) financial statement expense 67 (141) --- Amortization of materials and supplies not currently deductible (335) (343) (239) Low-level waste deduction over (under) financial statement expense (596) 139 825 Flowback of excess deferred taxes (442) (376) (828) Other 191 (23) 245 ______ ______ ______ $ (979) $(2,169) $ (801) ====== ====== ======
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 1993 and January 1, 1993 are presented below:
The net periodic postretirement benefit cost for 1993 and 1992 includes the following components (dollars in thousands):
For measurement purposes, a 15% annual rate of increase in the per capita cost of covered benefits (i.e., health care cost trend rate) was assumed for 1993; the rate was assumed to decrease gradually to 6% by the year 2001 and remain at that level thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. For example, increasing the assumed health care cost trend rates by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 1993 by $2.2 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year ended December 31, 1993 by $0.3 million. The weighted-average discount rate used in determining the accumulated postretirement benefit obligation was 7% at December 31, 1993.
The change in the accumulated postretirement benefit obligation from $12.5 million in 1992 to $10.0 million in 1993 is the result of adjustments made to reflect a lower actual medical cost increase during 1993 than projected. The reduction in the unrecognized net transition obligation from $10.3 million in 1992 to $7.9 million in 1993 is primarily the result of elimination of Medicare Part B coverage.
NOTE 14. Lease Commitments
The Company leases equipment and systems under noncancelable operating leases. Charges against income for rentals under these leases were approximately $3.7 million, $2.6 million and $3.7 million in 1993, 1992 and 1991, respectively. Minimum future rentals as of December 31, 1993 are as follows:
Fiscal years ended Annual rentals - ------------------ -------------- (Dollars in thousands)
1994 $3,283 1995 3,060 1996 2,878 1997 2,798 1998 and after 5,053
The Company has entered into an agreement with General Electric Capital Corporation to lease certain equipment being constructed by General Electric Corporation valued at approximately $29 million including installation costs. Under the lease agreement, the Company will make 120 monthly payments of $342,358 per month commencing on the later of (1) April 15, 1995 or (2) the commissioning date of the equipment. The lease will also include the sale and leaseback of a $2 million turbine rotor forging previously owned by the Company. The lease will be classified as an operating lease for accounting purposes.
The construction contract requires progress payments to be paid by Vermont Yankee prior to installation of the equipment. Just prior to delivery of the equipment, the lessor will reimburse Vermont Yankee for these payments and will continue to make the remaining payments until the commencement date of the lease. During the time period subsequent to equipment delivery before the equipment is commissioned, the Company will pay interim rent to the lessor based on the amount of outstanding progress payments. The final documentation of the lease is currently being negotiated, and if a final agreement cannot be reached, the Company would be responsible for substantial termination payments.
NOTE 15. Commitments and Contingencies
Low-level Waste
In February, 1993, the Vermont Public Service Board issued an order which requires the Company to pay its share of expenses incurred by the Vermont Low Level Radioactive Waste Authority for the period April, 1993 through June, 1994, currently capped at $4.5 million. In addition, in accordance with Vermont Act 296, the order established a fund for the long-term care of any eventual Vermont low-level waste disposal facility. Based on this order, the Company must make annual payments of approximately $0.8 million into the long-term care fund. Payments made to the VLLRWA, not pertaining directly to the siting and construction of a low-level waste disposal facility, are being expensed currently.
In parallel with siting a low-level radioactive waste facility in Vermont, there has been a three-state effort between Vermont, Maine, and Texas to form a compact to site such a facility in Texas. The Texas Legislature has approved, and Governor Ann Richards of Texas has signed into law, a bill that would form such a compact. On November 2, 1993, Maine voters ratified the compact. Early during its 1994 session, the Vermont Legislature is scheduled to vote to approve entry into the compact. Following approval by the Vermont Legislature, the compact will require approval of the U.S. Congress.
If the compact is successful and proceeds on schedule, Vermont Yankee would begin sending its waste to a Texas facility during 1997. Under the proposed compact, Vermont would pay the State of Texas $25 million ($12.5 million when the U.S. Congress ratifies the compact and $12.5 million when the facility opens). In addition, Vermont must pay $2.5 million ($1.25 million when Congress ratifies the compact and $1.25 million when the facility is licensed) for community assistance projects in Hudspeth County, Texas, where the facility is to be located. Vermont would also pay one-third of the Texas Low-Level Radioactive Waste Disposal Compact Commission's expenses until the facility opens. The Disposal fees for generators in Vermont and Maine would then be set at a level that is the same for generators in Texas. The Company anticipates recovering the costs of the compact from sponsors.
Nuclear Fuel
The Company has approximately $165 million of "requirements based" purchase contracts for nuclear fuel needs to meet substantially all of its power production requirements through 2002. Under these contracts, any disruption of operating activity would allow the Company to cancel or postpone deliveries until actually needed.
Insurance
The Price-Anderson Act, as amended, currently limits public liability from a single incident at a nuclear power plant to $9.4 billion. Any damages beyond $9.4 billion are indemnified under an agreement with the NRC, but subject to Congressional approval. The first $200 million of liability coverage is the maximum provided by private insurance. The Secondary Financial Protection program is a retrospective insurance plan providing additional coverage up to $9.2 billion per incident by assessing retrospective premiums of $79.3 million against each of the 116 reactor units that are currently subject to the Program in the United States, limited to a maximum assessment of $10 million per incident per nuclear unit in any one year. The maximum assessment is to be adjusted at least every five years to reflect inflationary changes.
The above insurance covers all workers employed at nuclear facilities prior to January 1, 1988, for bodily injury claims. The Company has purchased a Master Worker insurance policy with limits of $200 million with one automatic reinstatement of policy limits to cover workers employed on or after January 1, 1988. Vermont Yankee's estimated contingent liability for a retrospective premium on the Master Workers policy as of December, 1993 is $3.1 million. The Secondary Financial Protection program referenced above provides coverage in excess of the Master Worker policy.
Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL II) to cover the costs of property damage, decontamination or premature decommissioning resulting from a nuclear incident. All companies insured with NEIL II are subject to retroactive assessments if losses exceed the accumulated funds available to NEIL II. The maximum potential assessment against the Company with respect to losses arising during the current policy year is $5.8 million at the time of a first loss and $12.3 million at the time of a subsequent loss. The Company's liability for the retrospective premium adjustment for any policy year ceases six years after the end of that policy year unless prior demand has been made.
VERMONT YANKEE NUCLEAR POWER CORPORATION
Schedule I
Marketable Securities - Other Investments
VERMONT YANKEE NUCLEAR POWER CORPORATION
Schedule V - Property, Plant and Equipment
Years Ended December 31, 1993, 1992, and 1991
($000)
1993 1992 1991 ---- ---- ----
Electric Plant:
Land and land rights $ 1,397 $ 1,127 $ 984 Structures and improvements 61,887 61,868 61,515 Reactor, turbogenerator and accessory equipment 304,388 292,561 285,808 Transmission equipment 5,948 5,606 6,141 Other 1,116 1,116 1,116 Construction work in progress 597 6,408 4,188 _______ _______ _______ 375,333 368,686 359,752 _______ _______ _______
Nuclear Fuel:
Assemblies in reactor 69,063 74,025 83,213 Fuel in process --- 5,236 637 Fuel in stock --- --- 22,863 Spent fuel 287,700 259,199 227,040 _______ _______ _______ 356,763 338,460 333,753 _______ _______ _______ Total $732,096 $707,146 $693,505 ======= ======= =======
Neither total additions of $25,361,000, $15,167,000 or $25,002,000 nor total retirements of $411,000, $1,526,000, or $0 for the years ended December 31, 1993, 1992 and 1991, respectively, exceeded 10% of the utility plant balance at the end of the year.
VERMONT YANKEE NUCLEAR POWER CORPORATION
Schedule VI - Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment
Years Ended December 31, 1993, 1992 and 1991
(Dollars in Thousands)
EXHIBIT 23-a-2 CONSENT OF INDEPENDENT AUDITORS
The Board of Directors Green Mountain Nuclear Power Corporation:
We consent to the incorporation by reference in the Registration Statement on Form S-3, File No. 3-48882 and in the Registration Statement on Form S-8, File No. 33-47985, of our report dated February 5, 1993, relating to the balance sheet of Vermont Yankee Nuclear Power Corporation as of December 31, 1992 and the related statements of income and retained earnings and cash flows for each of the years in the two- year period ended December 31, 1992, which report is included in the December 31, 1993 Annual Report on Form 10-K of Green Mountain Power Corporation.
Boston, Massachusetts March 28, 1994 KPMG Peat Marwick
EXHIBIT 23-a-1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our reports dated February 1, 1994 included in this Form 10-K, into the Company's previously filed Registration Statement on Form S-3, File No. 33-48882, and into the Company's previously filed Registration Statement on Form S-8, File No. 33-47985.
Boston, Massachusetts March 30, 1994 /s/ Arthur Andersen & Co.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Green Mountain Power Corporation:
We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements of Green Mountain Power Corporation included in this Form 10-K and have issued our report thereon dated February 1, 1994. Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the index on page 38 of this Form 10-K are the responsibility of the Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements, and in our opinion, fairly state, in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Boston, Massachusetts February 1, 1994 /s/ Arthur Andersen & Co.