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 80,500 customers. For the year ended December 31, 1994, the Company's sources of revenue were derived as follows: 33.6% from residential customers, 31.9% from small commercial and industrial customers, 20.7% from large commercial and industrial customers, 8.9% from sales to other utilities, and 4.9% from other sources. For the same period, the Company's energy resources for retail and requirements wholesale sales were obtained as follows: 38.7% from hydroelectric sources (5.8% Company-owned, 0.5% New York Power Authority (NYPA), 29.6% Hydro-Quebec and 2.8% small power producers), 36.2% from nuclear generating sources (the Vermont Yankee plant described below), 10.9% from coal sources, 3.3% from wood, 0.5% from natural gas, and 0.9% from oil. The remaining 9.5% was purchased on a short-term basis from other utilities and through the New England Power Pool (NEPOOL). In 1994, the Company purchased 93.1% 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 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 1994, the Company also supplied four firm wholesale customers, including one municipal and two cooperative utilities in Vermont and one utility in another state. 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, 1994, 1993 and 1992, electric energy sales to International Business Machines Corporation (IBM), the Company's largest customer, accounted for 13.7%, 13.6% and 13.8%, 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 was needed primarily to cover the cost of buying power from independent power producers, the cost of energy efficiency programs, the cost of plant additions made in the prior 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 was approved by the VPSB on May 13, 1994.
On September 26, 1994, the Company filed a request with the VPSB to increase retail rates by 13.9%. The increase is needed primarily to cover the rising cost of existing power sources, the cost of new power sources the Company has secured to replace power supply that will be lost in the near future, and the cost of energy efficiency programs the Company has implemented for its customers.
The Company, the Vermont Department of Public Service (the Department), and the other parties in the proceeding reached a settlement agreement providing for a 9.25% retail rate increase effective June 15, 1995, and a target return on equity of 11.25%. 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 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 1992-1994, internally generated funds, after payment of dividends, provided approximately 56% of total capital requirements for construction, sinking fund obligations and other requirements. Internally generated funds provided 84% of such requirements for 1994. It is expected that funds so generated will provide approximately 90% of such requirements for the period 1995 through 1999, with the remainder to be derived through short-term borrowings and the issuance of long- term debt securities and common and preferred stock.
The Company anticipates issuing $15,000,000 of common stock and $10,000,000 of first mortgage bonds in 1995. The proceeds will be used to finance capital projects and to retire short-term debt. The amount and timing of such issuances 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
DEMAND-SIDE MANAGEMENT
The Company has committed itself to the development and implementation of demand-side management (DSM) 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. DSM 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.
In 1994, the Company refocused its energy efficiency programs to reflect the new realities of greater power supply availability and to capture efficiencies gained from prior experience with DSM. The shift in focus reduced the Company's DSM costs in 1994 from $8,100,000 to $6,400,000.
The framework for DSM developed with the Department also addresses the need for greater cost-consciousness, not only by deploying DSM in a more strategic manner, but also by beginning to shift, where appropriate, more of the cost for DSM towards the customers who will be receiving the most benefit. These programs are part of the Company's most recent rate settlement. If such settlement is approved by the VPSB, the new programs are scheduled to begin operation in April 1995.
The Company exceeded its savings goals by 16% in 1994, after reducing the scope of the programs, while at the same time strengthening the economic benefit of these programs and services.
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 2,500 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 rate design that permitted it to charge prices for electric service that reflected 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 largest customers be charged time-of-use rates on a phased-in basis by 1994. Approximately 1,400 of the Company's largest customers, comprising 48% of retail revenues, were successfully converted to time-of-use rates. In May 1994, the Company filed a new rate design case with the VPSB. The parties, including the Department, IBM and a low-income advocacy group, entered into a settlement that was approved by the VPSB on December 2, 1994. Under the settlement, the revenue allocation to each rate class was adjusted to reflect class-by-class cost changes since 1987, the differential between the winter and summer rates was reduced, the customer charge was increased for most classes, and usage charges were adjusted to be closer to the associated marginal costs.
Dispatchable and Interruptible Service Contracts. In 1994, the Company had interruptible/dispatchable power contracts with three major ski areas, interruptible only contracts with three customers and dispatchable-only contracts with an additional thirteen customers. The interruptible portion of the contracts allow the Company to control power supply capacity charges by reducing the Company's capacity requirements. During 1994, the Company did not request any interruptions due to the surplus capacity in the region. The dispatchable portion of the contracts allows customers to purchase electricity during times designated by the Company when low cost power is available at the energy only cost of the rate. The customers' demand during these periods is not considered in calculating the monthly billing. This program provides customers with discretionary use of portions of their load the opportunity to maximize their energy value and at the same time the Company is able to retain customer load requirements that might otherwise be met through alternative means. These programs are available by tariff for qualifying customers.
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 approximately 7,000 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 1994, the Company offered five commercial and industrial energy efficiency programs to qualifying customers. These programs offered comprehensive technical assistance to identify cost-effective electric energy efficiency opportunities which may qualify for financial incentives. In addition, fuel-switching opportunities were identified for customers, although no direct financial incentives were provided. Approximately 600 customers participated in these programs in 1994, resulting in an approximate savings of 12,900 MWh.
Residential Energy Management Services. In 1994, the Company offered four DSM 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 8,000 residential customers participated in these programs in 1994 resulting in an annual savings of approximately 1,884 MWh, or approximately 18% greater than projected.
POWER RESOURCES
The Company generated and purchased 1,828,663.8 MWh of energy for retail and requirements wholesale customers for the twelve months ended December 31, 1994. The corresponding maximum one-hour integrated demand during that period was 308.3 MW on January 26, 1994. This compares to the previous all-time peak of 322.6 MW on December 27, 1989. The following tabulation shows 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."
Net Generated and Net Generated and Purchased Year Purchased in Month Ended 12/31/94 (a) of Annual Peak ___________________ ___________________ MWh % KW % WHOLLY OWNED PLANTS Hydro 108,520.1 5.84 37,216 8.49 Diesel and Gas Turbine 2,026.2 0.11 69,247 15.80
JOINTLY OWNED PLANTS Wyman #4 4,667.6 0.25 8,254 1.88 Stony Brook I 5,877.6 0.32 8,793 2.01 McNeil 5,800.9 0.31 5,887 1.34
OWNED IN ASSOCIATION W/OTHERS Vermont Yankee Nuclear (b) 672,945.2 36.21 80,872 18.45
NYPA LEASE TRANSMISSIONS State of Vermont (NYPA) 9,618.7 0.52 2,088 0.48
LONG-TERM PURCHASES Hydro-Quebec 550,508.6 29.62 124,408 28.39 Merrimack #2 202,987.3 10.92 30,457 6.95 Stony Brook I 11,409.4 0.61 13,768 3.15 Small Power Producers 107,580.7 5.79 24,024 5.48
SHORT-TERM PURCHASES 176,637.0 9.50 33,208 7.58 ___________ _____ _______ _____ Less System Sales Energy (29,915.5)
TOTAL 1,828,663.8 100.00 438,222 100.00 =========== ====== ======= ======
NOTE: (a) Excludes losses on off-system purchases, totaling 40,765 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.
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. On March 16, 1995, Vermont Yankee began a scheduled refueling outage which is expected to be completed by mid-April 1995. Vermont Yankee's next scheduled refueling is September 1996. 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 $2,086,000 in 1994, $7,229,000 in 1993 and $10,750,000 in 1992. Vermont Yankee estimates capital expenditures amounting to approximately $2,507,000 for 1995.
During the year ended December 31, 1994, the Company utilized 672,945.2 MWh of Vermont Yankee energy to meet 36.2% of its retail and requirements wholesale sales. The average cost of electricity produced by the plant in 1994 was 3.8 cents per KWh. In 1994, Vermont Yankee had an annual capacity factor of 96.1%, compared to 76.9% in 1993 and 83.3% in 1992.
The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $8,900,000,000. Any liability beyond $8,900,000,000 is indemnified under an agreement with the NRC, but subject to Congressional approval. 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 $8,700,000,000 per incident by assessing retrospective premiums of $79,300,000 against each of the 110 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 $13,100,000. 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 and NEIL III) to cover the costs of property damage, decontamination or premature decommissioning resulting from a nuclear incident. All companies insured with NEIL II and III are subject to retroactive assessments if losses exceed the accumulated funds available. The maximum potential assessment against Vermont Yankee with respect to NEIL II losses arising during the current policy year is $6,400,000 at the time of the first loss and $13,800,000 at the time of a subsequent loss and the NEIL III maximum retroactive assessment is $8,400,000. 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. On February 11, 1995, the transmission facilities maximum capability was upgraded from 200 MW to 225 MW.
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, 1994, the present value of the Company's obligation was $10,300,000. The Company's projected future minimum principal payments under the Phase II support agreements are $489,425 for each of the years 1995-1999 and an aggregate of $7,830,817 for the years 2000-2020.
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, 1994, the capital structure of such corporations was 41% common equity and 59% 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.
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 1994, 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 1995. The Company anticipates that purchases of tertiary energy will extend beyond August 1995, 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. During 1994, the Company negotiated an arrangement with Hydro-Quebec that reduces the cost impacts associated with the purchase of Schedules B and C3 under the December 1987 contract, over the November 1995 through October 1999 period. Under this new arrangement, the Company, in essence, will take delivery of the amounts of energy as specified in the December 1987 contract, but the associated fixed costs will be significantly reduced from those specified in the December 1987 contract.
As part of this arrangement, the Company will purchase $3,000,000 worth of research and development work from Hydro-Quebec over the four- year period and is obligated to make $7,500,000 cash payment to Hydro- Quebec in 1995. The Company has the option to purchase up to $1,000,000 worth of additional research and development work. If the Company exercises its option, the $7,500,000 cash payment will be reduced accordingly. Hydro-Quebec retains the right to curtail annual energy deliveries by 13% up to five times, over the 2000 to 2015 period, if documented drought conditions exist in Quebec.
During the first year of this arrangement, the average cost per KWh of Schedules B and C3 will be cut from 6.2 cents to 4.2 cents per KWh, a 32% or $15,000,000 cost reduction. Over the four-year period covered by the arrangement, unit costs will be lowered from 6.4 cents to 5.2 cents per KWh, reducing unit costs by 19% and saving $34,500,000 in nominal terms.
In 1994, the Company utilized 356,591.9 MWh of Hydro-Quebec energy under the July 1984 contract, 77,808.3 MWh under the December 1987 contract Schedule A and 116,108.4 MWh under the tertiary energy contract to meet 29.6% of its retail and requirements wholesale sales. The average cost of Hydro-Quebec electricity in 1994 was 3.0 cents per KWh. See Notes J and K-2 of Notes to Consolidated Financial Statements.
New York Power Authority (NYPA). The Department allocates NYPA power to the Company who, in turn, delivers the power to its residential and farm customers. The Company purchased at wholesale 9,618.7 MWh of NYPA power at an average cost of 1.1 cents per KWh in 1994. 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 1994 - June 1995 0.3 July 1995 - June 1996 0.3 July 1996 - June 1997 0.3 July 1997 - June 1998 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, 1994, the Company utilized 202,987.3 MWh from the unit to meet 10.9% of its total retail and requirements wholesale sales. The average cost of electricity from this unit was 3.2 cents per KWh in 1994. 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 1994, the Company utilized 17,287.0 MWh from this plant to meet 0.9% of its retail and requirements wholesale sales at an average cost of 11.0 cents per Kwh, the portion of these costs attributable to the 30.2 MW joint ownership share are based only on operation, maintenance, and fuel costs incurred in 1994. See Note I-3 and K-1 of Notes to Consolidated Financial Statements.
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 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 1994, the Company utilized 4,667.6 MWh from this unit to meet 0.3% of its retail and requirements wholesale sales at an average cost of 4.3 cents per Kwh, based only on operation, maintenance, and fuel costs incurred during 1994. 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 1994, the Company utilized 5,800.9 MWh from this unit to meet 0.3% of its retail and requirements wholesale sales at an average cost of 6.1 cents per Kwh, based only on operation, maintenance, and fuel costs incurred during 1994. 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. 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 agreement 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 agreement and the transmission contract with Niagara Mohawk that supports it effective October 31, 1995. The Company also agreed to offer power it obtained from RG&E to CL&P for purchase on a weekly basis through the remaining term of the RG&E agreement and 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 replaced the Company as the supplier of electricity to Bozrah, assumed responsibility for approximately 75% of the fixed costs of the transmission contract with Niagara Mohawk, and provided 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 agreement. 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 arrangement was approved by FERC effective May 1, 1993. The reductions in the Company's 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 agreement with Bozrah.
In January 1995, CL&P and the Company signed an amendment to the agreement to enable the Company to terminate the RG&E agreement in January 1995, to eliminate the provisions relating to the sale of capacity and energy by the Company and to provide a price ceiling to substitute for the RG&E agreement price ceiling as it applies to the Company's purchase from CL&P. Additionally, contract terms for the Company's option to purchase up to 50 MW of CL&P system power were amended to make the power available August 1995-December 2004, and the Company's deadline for initial elections of said power was extended to July 31, 1995. Costs associated with this arrangement are as follows:
Charges Annual Transmission Reservations . . . . . $300,000 Average Cost per kWh . . . . . . . . . . . 3.3 cents (1994) 3.3 cents (1995 estimated)
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 of 1978 (PURPA). 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 approximately 32.4% or 48.7 MW.
In 1994, the Company, through both its direct contracts and the Vermont Power Exchange, purchased 107,580.7 MWh of small power production to meet 5.8% of its retail and requirements wholesale sales at an average cost of 10.2 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 1994, the Company purchased 176,637.0 MWh, 9.5% of the Company's retail and requirements wholesale sales, at an average cost of 2.5 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 1994, these plants provided 108,520.1 MWh of low-cost energy, meeting 5.8% of the Company's retail and requirements wholesale sales at an average cost of 1.0 cents per Kwh, based only on operation, maintenance, and fuel costs incurred in 1994. 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 1994, the Company's retail and requirements wholesale sales were provided by the following fuel sources: 38.7% from hydro (5.8% Company-owned, 0.5% NYPA, 29.6% Hydro-Quebec and 2.8% small power producers), 36.2% from nuclear, 10.9% from coal, 3.3% from wood, 0.5% from natural gas, and 0.9% from oil. The remaining 9.5% was purchased on a short-term basis from other utilities and through NEPOOL.
Vermont Yankee has approximately $133 million of "requirements based" purchase contracts for nuclear fuel needs to meet substantially all of its power production requirements through 2002. Under these contracts, any disruption of operating activity would allow Vermont Yankee to cancel or postpone deliveries until actually needed.
Vermont Yankee has 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 contract to be prior to January 31, 1998.
The DOE contract obligates Vermont Yankee to pay a one-time fee of approximately $39.3 million for disposal costs for all spent fuel discharged through April 7, 1983. Although such amount has been collected in rates from the Vermont Yankee participants, Vermont Yankee has elected to defer payment of the fee to the DOE as permitted by the DOE contract. The fee must be paid no later than the first delivery of spent nuclear fuel to the DOE. Interest accrues on the unpaid obligation based on the thirteen-week Treasury Bill rate and is compounded quarterly. Through 1994, Vermont Yankee accumulated approximately $54 million in an irrevocable trust to be used exclusively for defeasing this obligation at some future date, provided the DOE complies with the terms of the aforementioned contract.
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 1994, and, while no assurance can be given, does not anticipate any such difficulty during 1995. None of the utilities from which the Company expects to purchase oil- or gas-fired capacity in 1995 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 23, 1995, there was a 72-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 129,128 tons of wood chips and mill residue and 157,682,000 cubic feet of gas in 1994. The McNeil plant is forecasting consumption of wood chips for 1995 to be 120,000 tons and gas consumption of 300,000,000 cubic feet. Burlington Electric Department advises that, as of February 18, 1995, there were 33,904 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 has entered into two economic development agreements, providing for reduced charges to large customers to be applied only to new load. A third economic development agreement with IBM is part of the rate settlement currently before the VPSB referenced above.
The Company's wholesale rate on sales to four wholesale customers is regulated by the FERC. Revenues from sales to these customers were approximately 1.5% of operating revenues for 1994.
Late in 1989, the Company began serving a municipal utility, Northfield Electric Department, under its wholesale tariff. This customer increased the Company's electricity sales by approximately 23,461 MWh and peak requirements by approximately 6 MW. Revenues in 1994 from Northfield were $1,294,165.
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 1994.
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 in 1995. 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. In December 1994, 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 future electrical energy demand.
The Company's next Integrated Resource Plan, scheduled to be publised in June 1995, will be developed in a manner consistent with the Department's Plan. The 1995 Integrated Resource Plan will call for a greater emphasis on distributed utility approaches that can best use the Company's assets, maximize the benefit of demand-side management programs, and provide customers with the highest quality service.
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.
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 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 or before 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 facilitator. The council is charged with determining what additional studies may be appropriate for the site and also is planning to eventually address additional response activities.
In July 1994, the Company, New England Electric System (NEES), and Vermont Gas Systems, Inc. (VGS), entered into an Administrative Order by Consent, with the EPA, pursuant to which these PRPs are conducting certain additional studies that have been agreed to by the coordinating council. These studies constitute the first phase of action the council has decided on to fill data gaps at the site. A second phase, including tasks carried over from the first phase, additional field studies and preparation of an addendum feasibility study is expected to be performed during 1995 by the same parties under a second Order. The EPA has not required 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.
On December 1, 1994, the Company, NEES and VGS entered into a confidential agreement with the State, the City of Burlington and nearly all other landowner PRPs under which the liability of those landowner PRPs for future Superfund response costs would be limited and specified. On December 1, 1994, the Company entered into a confidential agreement with VGS compromising contribution and cost recovery claims of each party and contractual indemnity claims of the Company arising from the 1964 sale of the manufactured gas plant to VGS, and also entered into a confidential agreement with NEES for funding of work under the Administrative Order.
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. Discovery in the case is largely complete, with the exception of expert discovery which was stayed by the magistrate pending the resolution of Summary Judgment Motions filed by the Company. In August 1994, the Magistrate granted the Company's Motion for Summary Judgment with respect to defense costs against one defendant and denied it against another defendant. The United States District Judge affirmed those orders on September 30, 1994.
The Company has reached confidential settlements with two of the defendants in its insurance litigation. One of these defendants 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 other defendant provided the Company with second layer excess liability coverage for a seven-month period in 1976.
The Company has deferred amounts received from third parties pending resolution of the Company's ultimate liability with respect to the site and rate recognition of that liability. 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.
Through rate cases filed in 1991 and 1993, the Company has sought and received recovery for ongoing expenses associated with the Pine Street Marsh site. Specifically, the Company proposed rate recognition of its unrecovered expenditures between January 1991 and July 31, 1993 (in the total of approximately $4,600,000) 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 (the Department) reached agreements in both cases that the full amount of Pine Street Marsh costs reflected in those rate cases should be recovered in rates. The Company's rates approved by the VPSB on April 2, 1992, and on May 13, 1994, reflected the Pine Street Marsh related expenditures referred to above.
In a rate case filed on September 26, 1994, the Company sought recovery in rates of approximately $2,700,000 in expenses associated with the Pine Street site. This amount represented the Company's unrecovered expenditures between August 1993 and June 1994 for technical consultants and legal assistance in connection with EPA's enforcement action at the site and insurance litigation. While reserving the right to argue in the future about the appropriateness of rate recovery for Pine Street related costs (and whether recovery or non-recovery of past costs and any insurance proceeds is relevant to such issue), the parties to the case have reached agreement that the full amount of Pine Street costs reflected in the Company's 1994 rate case should be recovered in rates. This agreement is currently pending before the VPSB.
Management expects to seek and (assuming treatment consistent with the previous regulatory treatment set forth above) receive ratemaking treatment for unreimbursed costs incurred beyond the amounts for which ratemaking treatment has been received. As of December 31, 1994, such amounts are approximately $845,000.
COMPETITION
The Company serves a fixed area of Vermont under a VPSB franchise. Except as noted below, the Company's electric business is substantially free from competition for retail customers 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.
The VPSB and the Department are currently conducting a roundtable discussion with Vermont utilities, customer groups and other organizations concerning the potential for expanded retail competition in Vermont and any structural changes in the industry that will be required. It is expected that the roundtable will complete its work by July 1995.
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 1994 1993 (In thousands) Revenue . . . . . . . . . . . . . . . $12,031 $11,487 Expense . . . . . . . . . . . . . . . 10,920 11,527 ------- --------- Net Income (Loss) . . . . . . . . . . $ 1,111 ($ 40) ======= =========
EMPLOYEES
The Company had 373 employees, exclusive of temporary employees, as of December 31, 1994. In addition, subsidiaries of the Company had 59 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 1994 peak of 308.3 MW occurred on January 26, 1994. 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 30% higher than during the eight off-season months (April through November). See discussion -- Demand-Side Management -- Rate Design.
EXECUTIVE OFFICERS
Executive Officers of the Company as of March 31, 1995:
Name Age Douglas G. Hyde 52 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 61 Executive Vice President and Chief Operating Officer since January 1995. Senior Vice President and Chief Operating Officer from 1993 to 1995. Senior Vice President from 1984 to 1993. President - Mountain Energy, Inc. since December 1989.
Edwin M. Norse 49 Vice President and General Manager, Energy Resources and Sales since January 1995. Vice President, Chief Financial Officer and Treasurer from 1986 to January 1995. President-Green Mountain Propane Gas Company since October 1993.
Christopher L. Dutton 46 Vice President, Finance and Administration, Chief Financial Officer and Treasurer since January 1995. Vice President and General Counsel from 1993 to January 1995. Vice President, General Counsel and Corporate Secretary from 1989 to 1993. General Counsel and Corporate Secretary from 1984 to 1989.
Glenn J. Purcell 61 Controller since September 1986.
Thomas C. Boucher 40 Vice President, Energy Resources and Planning since January 1995. Vice President- Corporate Planning from 1994 to 1995. Vice President, Financial Planning from 1992 to 1994. Assistant Vice President-Energy Planning from 1986 to 1992.
Stephen C. Terry 52 Vice President and General Manager, Retail Energy Services since January 1995. Vice President-External Affairs from 1991 to January 1995. Assistant Vice President- Corporate Relations from 1986 to 1991.
Walter S. Oakes 48 Assistant Vice President-Customer Operations since June 1994. Assistant Vice President-Human Resources from August 1993 to June 1994. Assistant Vice President- Corporate Services from 1988 to 1993.
Robert C. Young 57 Assistant Vice President-Customer Operations since 1994. Assistant Vice President-Operations and Engineering from 1992 to 1994. 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 43 Assistant Vice President-Human Resources and Organizational Development since January 1995. Assistant General Counsel from 1989 to 1995. Senior Attorney from 1988 to 1989.
Craig T. Myotte 40 Assistant Vice President-Engineering and Operations since 1994. Assistant Vice President-Operations and Maintenance from 1991 to 1994. Director-System Operations from 1986 to 1991.
John J. Lampron 50 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 45 Corporate Secretary since December 1993. Assistant Secretary from 1986 to 1993.
Peter H. Zamore 42 General Counsel since January 1995. Prior to joining the Company, he was a partner at the law firm of Sheehey Brue Gray & Furlong, P.C. from 1984 to 1995.
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 a total nameplate rating of 36.4 MW and an estimated effective capability of 35.3 MW. It also owns two gas-turbine generating stations with an aggregate nameplate rating of 59.9 MW and an estimated effective capability of 60.3 MW. The Company has two diesel generating stations with an aggregate nameplate rating of 8.0 MW and an estimated effective capability of 8.4 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, 1994, approximately 1.5 miles of 115-kV transmission lines, 9.4 miles of 69 kV transmission lines, 5.4 miles of 44-kV and 265.4 miles of 34.5 kV transmission lines. Its distribution system included about 2,361 miles of overhead lines, 2.4 kV to 34.5 kV, and about 404 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 1,243,450 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 3.3 Marshfield, VT Marshfield #6 Hydro 4.9 Vergennes, VT Vergennes #9 Hydro 2.1 W. Danville, VT W. Danville #15 Hydro 1.1
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 7.8
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 30.9(2) _____ Total Winter Capability 249.9
(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 1994 and 1993:
HIGH LOW
1994 First Quarter 31 1/4 27 1/2 Second Quarter 30 23 3/4 Third Quarter 27 3/8 23 3/8 Fourth Quarter 28 1/8 23 7/8
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
The number of common stockholders of record as of March 15, 1995 was 6,456.
Quarterly cash dividends were paid as follows for the past two years:
First Second Third Fourth Quarter Quarter Quarter Quarter
1994 53 cents 53 cents 53 cents 53 cents 1993 52 1/2 cents 52 1/2 cents 53 cents 53 cents
SELECTED FINANCIAL DATA (In thousands except per share amounts)
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 1994 were $2.23 as compared with $2.20 in 1993. The 1994 earnings represent an earned return on average common equity of 10.3 percent. In 1993 and 1992, the earned return on equity was 10.3 and 12.2 percent, respectively.
The 1994 increase in earnings was primarily due to a $722,000 increase in the earnings of Mountain Energy, Inc., the Company's wholly-owned subsidiary that invests in electric energy-related development projects, and a $523,000 increase in earnings of Green Mountain Propane Gas Company, the Company's wholly-owned propane subsidiary. This increase was partially offset by an adverse ruling by the Vermont Supreme Court reversing an order of the Vermont Public Service Board (VPSB) in a 1991 rate decision and the effects of warmer than normal winter weather during the fourth quarter.
The principal factor contributing to the decrease in 1993 earnings from 1992 was a nearly two-fold increase in purchases of electricity from independent power producers mandated by federal and state laws.
Operating Revenues and MWH Sales -- Operating revenues and MWH sales for the years 1994, 1993 and 1992 consisted of:
1994 1993 1992 (Dollars in Thousands) Operating Revenues: Retail . . . . . . . . . . . . . $ 131,444 $ 130,061 $ 126,057 Sales for Resale . . . . . . . . 13,521 14,441 17,258 Other . . . . . . . . . . . . . 3,232 2,751 1,925 ---------- ---------- ---------- Total Operating Revenues . . . . . $ 148,197 $ 147,253 $ 145,240 ========== ========== ========== Megawatthour Sales: Retail . . . . . . . . . . . . . 1,691,867 1,688,803 1,692,179 Sales for Resale. . . . . . . . 367,424 331,875 375,894 --------- ---------- ---------- Total Megawatthour Sales . . . . . 2,059,291 2,020,678 2,068,073 ========= ========== ========== Average Number of Customers: Residential . . . . . . . . . . 68,811 67,994 67,201 Commercial & Industrial . . . . 11,635 11,472 11,269 Other . . . . . . . . . . . . . 76 74 73 ------ ------ ------ Total Customers . . . . . . . . . . 80,522 79,540 78,543 ====== ====== ======
Differences in operating revenues were due to changes in the following:
1993 1992 to to 1994 1993 (In Thousands) Operating Revenues: Retail Rates . . . . . . . . . . . . . . . $1,140 $4,269 Retail Sales Volume . . . . . . . . . . . 244 (265) Resales and Other Revenues . . . . . . . . (440) (1,991) ------- ------- Increase in Operating Revenues . . . . . . . $ 944 $2,013 ======= =======
In 1994, total electricity sales increased 1.9 percent due principally to colder than normal winter weather in the first quarter and warmer than normal summer weather. Total operating revenues increased 0.6 percent in 1994 due principally to a 2.9 percent rate increase that was effective in June 1994. Wholesale revenues decreased 6.4 percent in 1994 due principally to the greater availability of low-cost energy in New England, which drove down wholesale prices.
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 primarily due 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.
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 13.7, 13.6 and 13.8 percent of the Company's operating revenues in 1994, 1993 and 1992, respectively. No other retail customer accounted for more than one percent of the Company's revenue.
Power Supply Expenses -- Power supply expenses constituted 59.2 percent, 59.7 percent and 58.1 percent of total operating expenses for the years ended 1994, 1993 and 1992, respectively. These expenses increased by $190,000 (0.2 percent) in 1994, and by $4.1 million (5.5 percent) in 1993.
Power supply expenses were virtually unchanged in 1994 from 1993.
Power supply expenses increased in 1993 due primarily to a nearly two- fold increase in purchases of electricity from independent power producers mandated by federal and state laws.
Other Operating Expenses -- Other operating expenses were virtually unchanged in 1994 from 1993.
Other operating expenses were virtually unchanged in 1993 from 1992.
Transmission Expenses -- The Company's continuing restructuring of a series of transmission contracts produced a 3.7 percent decrease in transmission expenses in 1994.
The Company's restructuring of a series of transmission contracts produced a 3.0 percent decrease in transmission expenses in 1993.
Maintenance Expenses -- Maintenance expenses increased 2.6 percent in 1994 due principally to a scheduled increase in plant maintenance.
Maintenance expenses decreased 7.3 percent in 1993 due principally to scheduled increases in various capital projects that had the effect of reducing activity by Company employees on maintenance projects.
Depreciation and Amortization -- Depreciation and amortization expenses increased 24.6 percent in 1994 due principally to the amortization of expenditures related to energy conservation programs and to the Pine Street Marsh environmental matter (discussed in Note I of the Notes to Consolidated Financial Statements) and to additional investment in the Company's distribution facilities.
Depreciation and amortization expenses increased 6.3 percent in 1993, reflecting continuing additions to the Company's distribution facilities.
Income Taxes -- The effective federal tax rates for the years 1994, 1993 and 1992 were 25.1 percent, 28.9 percent and 28.8 percent, respectively.
Other Income -- Other income increased 39.8 percent in 1994 due primarily to an $722,000 increase in earnings of Mountain Energy, Inc., and a $523,000 increase in earnings of Green Mountain Propane Gas Company.
Other income increased 16.6 percent in 1993 due primarily to an increase in earnings of Mountain Energy, Inc., and to the VPSB's disallowance in 1992 of approximately $400,000 in construction costs sought to be recovered in a rate case.
Interest Charges -- Interest charges increased 5.4 percent in 1994 due primarily to interest charges related to the sale of $20 million of first mortgage bonds in November 1993 and to an increase in short-term debt outstanding during 1994.
Interest charges were virtually unchanged in 1993 from 1992.
Dividends on Preferred Stock -- Dividends on preferred stock decreased 2.1 percent in 1994 due primarily to the repurchase by the Company in 1993 of the following preferred stock: 300 shares of 4.75 percent, Class B and 1,600 shares of 9.375 percent, Class D, Series 1.
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.
Future Outlook -- The Company continues to implement 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 1.3 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 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.
Through rate cases filed in 1991 and 1993, the Company has sought and received recovery for ongoing expenses associated with the Pine Street Marsh site. Specifically, the Company proposed rate recognition of its unrecovered expenditures between January 1991 and July 31, 1993 (in the total of approximately $4.6 million) for technical consultants and legal assistance in connection with the Environmental Protection Agency (EPA) 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 (the Department) reached agreements in both cases that the full amount of Pine Street Marsh costs reflected in those rate cases should be recovered in rates. The Company's rates approved by the VPSB on April 2, 1992, and on May 13, 1994, reflected the Pine Street Marsh related expenditures referred to above.
In a rate case filed on September 26, 1994, the Company sought recovery in rates of approximately $2.7 million in expenses associated with the Pine Street site. This amount represented the Company's unrecovered expenditures between August 1993 and June 1994 for technical consultants and legal assistance in connection with EPA's enforcement action at the site and insurance litigation. While reserving the right to argue in the future about the appropriateness of rate recovery for Pine Street related costs (and whether recovery or non-recovery of past costs and any insurance proceeds is relevant to such issue), the parties in the case have reached agreement that the full amount of Pine Street costs reflected in the Company's 1994 rate case should be recovered in rates. This agreement is currently pending before the VPSB.
Management expects to seek and (assuming treatment consistent with the previous regulatory treatment set forth above) receive ratemaking treatment for unreimbursed costs incurred beyond the amounts for which ratemaking treatment has been received. As of December 31, 1994, such amounts are approximately $845,000.
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. The Company will continue to 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 unrecovered past costs and indemnity against future liabilities associated with environmental problems at the site. Discovery in the case is largely complete, with the exception of expert discovery which was stayed by the magistrate pending the resolution of Summary Judgment Motions filed by the Company. In August 1994, the Magistrate granted the Company's Motion for Summary Judgment with respect to defense costs against one defendant and denied it against another defendant. The United States District Judge affirmed those orders on September 30, 1994.
The Company has reached confidential settlements with two of the defendants in its insurance litigation. One of these defendants provided the Company with comprehensive general liability insurance between 1976 and 1982, and with environmental impairment liability insurance from 1981 and 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 other defendant provided the Company with second layer excess liability coverage for a seven-month period in 1976.
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) 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 1994 2,540 1,415 7,902 6,388 1,815 20,060 Forecasted 1995 $2,785 $1,038 $8,457 $3,698 $5,998 $21,976 1996 2,198 999 8,660 2,499 5,503 19,859 1997 1,299 1,499 8,999 2,444 2,102 16,343 1998 2,278 999 9,212 2,542 2,236 17,267 1999 2,777 999 9,509 2,643 2,137 18,065
Other Cash Requirements -- In 1995, the Company may devote $4 million to unregulated investments.
Rates -- On October 1, 1993, the Company filed a request with the VPSB to increase retail rates by 8.6 percent. The increase was 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 remedial investigation/feasibility study 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 above. The agreement was approved by the VPSB on May 13, 1994.
On September 26, 1994, the Company filed a request with the VPSB to increase retail rates by 13.9 percent. The increase is needed primarily to cover the rising cost of existing power sources, the cost of new power sources the Company has secured to replace power supply that will be lost in the near future, and the cost of energy efficiency programs the Company has implemented for its customers.
The Company, the Department, and the other parties in the proceeding reached a settlement agreement providing for a 9.25 percent retail rate increase effective June 15, 1995, and a target return on equity of 11.25 percent. The agreement must be reviewed and approved by the VPSB before it can take effect.
Financing and Capitalization -- For the period 1992 through 1994, internally generated funds, after payment of dividends, provided approximately 56 percent of total capital requirements for construction, sinking funds and other requirements. The Company anticipates that for the period 1995-1999, internally generated funds will provide approximately 90 percent of total capital requirements.
At December 31, 1994, the Company's capitalization consisted of 53.3 percent common equity, 41.9 percent long-term debt and 4.8 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 $15 million of common stock and $10 million of first mortgage bonds in 1995. The proceeds will be used to finance capital projects and to retire short-term debt.
The rating of the Company's first mortgage bonds was lowered in September 1994 by Standard & Poor's from "A-" to "BBB+", reflecting Standard & Poor's assessment that the electric utility industry is becoming increasingly more competitive. Standard & Poor's changed its "outlook" of the Company from "negative" to "stable", reflecting Standard & Poor's recognition of the Company's competitive rates, solid operations and management, and diverse fuel mix.
The rating of the Company's first mortgage bonds was lowered in January 1995 by Duff & Phelps from "A" to "A-", reflecting Duff & Phelps' assessment that the electric utility industry is becoming increasingly more competitive and that the Company is highly dependent on purchased power resulting in escalating fixed payment obligations. The rating of the Company's preferred stock was also lowered from "A-" to "BBB+". On a positive note, Duff & Phelps concluded that the Company's cost and rate structure is one of the lowest in New England, the Company's service territory has experienced minimal exposure to competitive forces and regulation is not expected to become a factor in the near term and should lag behind the rest of the nation.
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, 1994, 1993 and 1992 39
Consolidated Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992 40
Consolidated Balance Sheets as of December 31, 1994 and 1993 41
Consolidated Capitalization data as of December 31, 1994 and 1993 43
Notes to Consolidated Financial Statements 44
Report of Independent Public Accountants 66
Schedules
For the Years Ended December 31, 1994, 1993 and 1992:
II Valuation and Qualifying Accounts and Reserves 67
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
Arthur Andersen LLP 80
STATEMENTS OF CONSOLIDATED INCOME
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
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 1994 1993 (In thousands) Revenue . . . . . . . . . . . . . . . $12,031 $11,487 Expense. . . . . . . . . . . . . . . . 10,920 11,527 ------- --------- Net Income (Loss) . . . . . . . . . . $ 1,111 ($ 40) ======= =========
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: 1994 1993 1992 (In thousands) Interest . . . . . . . . . . . . . . . . $7,714 $6,206 $7,683 Income Taxes (Net of refunds) . . . . . $3,088 $1,920 $3,511
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 6.9 percent, 7.2 percent and 8.9 percent for the years 1994, 1993 and 1992, 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, 3.6 percent and 3.5 percent of total depreciable property at the beginning of the year for 1994, 1993 and 1992, 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 and amortizes 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, 1994 deferred charges totaled $35.7 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 and 1995 scheduled Vermont Yankee outages, 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 13.7, 13.6 and 13.8 percent of operating revenues in 1994, 1993 and 1992, 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: 1994 1993 1992 (Dollars in thousands) Service cost-benefits earned during the period . $ 768 $ 748 $ 676 Interest cost on projected benefit obligations . 1,633 1,593 1,466 Actual return on plan assets . . . . . . . . . . (1,296) (3,107) (1,743) Net amortization and deferral . . . . . . . . . . (906) 1,141 (77) Adjustment due to actions of regulator . . . . . (174) 337 430 ------- ------ ------ Net periodic pension cost funded and recognized . $ 25 $ 712 $ 752 ======= ====== ======
Assumptions used to determine pension costs in 1994, 1993 and 1992 were: Discount rate . . . . . . . . . . . . . . . . 7.5% 8.0% 8.0% Rate of increase in future compensation levels 5.0% 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: 1994 1993 1992 (In thousands) Actuarial present value of benefit obligations: Accumulated benefit obligations, including vested benefits of $18,184, $16,825 and $15,100, respectively . . . . . $(18,479) ($17,105) ($15,262) ========= ========= ========= Projected benefit obligations for service rendered to date . . . . . . . . . (21,363) ($21,002) ($19,235) Plan assets at fair value . . . . . . . . . . . 24,171 23,981 21,167 --------- --------- --------- Assets in excess of projected benefit obligations . . . . . . . . . . . . . 2,808 2,979 1,932 Unrecognized net loss (gain) from past experience different from that assumed . . . (285) (272) 559 Prior service cost not yet recognized in net periodic pension cost . . . . . . . . . . . . 1,642 1,885 2,028 Unrecognized net asset at transition being recognized over 16.47 years . . . . . . (1,934) (2,162) (2,391) Adjustment due to actions of regulator . . . . . (2,231) (2,430) (2,128) --------- --------- --------- Prepaid pension cost included in other assets . $ --- $ --- $ --- ========= ========= =========
As of December 31, 1994, the discount rate used to determine the accumulated benefit obligation was 8.0 percent.
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, 1994, 1993 and 1992 were $381,000, $384,000 and $377,000, respectively, under this plan. This plan is supported through insurance contracts.
11. Fair Value of Financial Instruments If the first mortgage bonds and preferred stock outstanding at December 31, 1994 were refinanced using new issue debt rates of interest, which, on average, are higher than the Company's outstanding rates, the present value of those obligations would differ from the amounts outstanding on the December 31, 1994 balance sheet by 3 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.
The VPSB requires the Company to fund postretirement health care costs. Accordingly, at December 31, 1993, the Company had deposited $2.1 million in an investment fund, which is included in other investments in the accompanying 1993 balance sheet. In January 1994, in order to maximize the tax deductible contributions that are allowed under IRS regulations, the Company amended its pension plan and established separate VEBA trusts for its union and nonunion employees. At December 31, 1994 all funds available for postretirement health care benefits, including the $2.1 million previously funded, were deposited in the VEBA trust.
The Company will seek and expects to receive rate recovery for all amounts expended for postretirement health care benefits.
Net postretirement benefits costs for 1994 reflect the following components and assumptions: 1994 1993 (In thousands) Accumulated postretirement benefit obligation: Current retirees . . . . . . . . . . . . . . . . . ($ 3,497) ($3,628) Participants currently eligible . . . . . . . . . (1,863) (2,288) All others . . . . . . . . . . . . . . . . . . . . (3,785) (4,789) --------- -------- Total accumulated postretirement benefit obligation . (9,145) (10,705) Plan assets at fair value . . . . . . . . . . . . . . 3,433 --- --------- -------- Accumulated postretirement benefit obligation in excess of plan assets . . . . . . . . . . . . . . . . . . (5,712) (10,705) Unrecognized transition obligation . . . . . . . . . 6,485 6,845 Unrecognized net loss (gain) . . . . . . . . . . . . (1,777) 538 --------- --------- Accrued postretirement benefit cost . . . . . . . . . ($ 1,004) ($ 3,322) ========= =========
Net periodic postretirement benefit cost for 1994 includes the following components: 1994 1993 (In thousands) Service cost . . . . . . . . . . . . . . . . . . . . $ 407 $ 438 Interest cost . . . . . . . . . . . . . . . . . . . 864 940 Actual return on plan assets . . . . . . . . . . . . (127) --- Deferred asset gain . . . . . . . . . . . . . . . . (107) --- Recognition of transition obligation, net of amortization . . . . . . . . . . . . . . . 361 380 ------- ------- Total net periodic postretirement benefit cost $ 1,398 $ 1,758 ======= =======
The discount rate used to determine postretirement benefit costs in 1994 was 7.5 percent; the discount rate used to determine the accumulated postretirement benefit obligation at December 31, 1994 was 8.5 percent.
For measurement purposes, an 11.5 percent annual rate of increase in the per capita cost of covered benefits was assumed for 1994; the rate was assumed to decrease gradually to 5.0 percent 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 rate by one percentage point would increase the accumulated postretirement benefit obligation as of December 31, 1994 by $1.5 million and the aggregate of the service and interest components of net periodic postretirement benefit cost for the year ended December 31, 1994 by $267,000.
13. Deferred Credits The Company has deferred credits and other long-term liabilities of $22.0 million, consisting of operating lease equalization, reserves for damage claims and environmental liabilities and accruals for employee benefits.
14. Reclassification Certain line items on the prior year balance sheet have been reclassified for consistent presentation with the current year.
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, 1994 1994 1993 (In thousands) VELCO - Common . . . . . . . . . 29.5% $ 1,814 $ 1,816 - Preferred . . . . . . . 30.0% 1,418 1,572 ------- ------- Total VELCO . . . . . . . . . . 3,232 3,388
Vermont Yankee - Common . . . . 17.9% 9,766 9,745
New England Hydro-Transmission - Common . . . . . . . . . . 3.18% 1,398 1,408
New England Hydro-Transmission Electric - Common . . . . . 3.18% 2,288 2,345 ------- ------- $16,684 $16,886 ======= =======
Undistributed earnings in associated companies totaled $1,089,000 at December 31, 1994.
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 $7.9 million, $8.0 million and $7.8 million for the years 1994, 1993 and 1992, 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, 1994 1993 1992 (In thousands) Company's equity in net income . . . . . . . $ 386 $ 406 $ 448 ======= ======= ======= Total assets . . . . . . . . . . . . . . . . $69,724 $70,199 $70,821 Less: Liabilities and long-term debt . . . . . 58,850 58,806 58,889 ------- ------- ------- Net assets . . . . . . . . . . . . . . . . . $10,874 $11,393 $11,932 ======= ======= ======= Company's equity in net assets . . . . . . . $ 3,232 $ 3,388 $ 3,554 ======= ======= ======= 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 $330 million in 1994 dollars, of which $115 million has been funded. At December 31, 1994, the Company's portion of the net unfunded liability was $37 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 1994, the Company incurred $24.2 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, 1994 was $13.1 million.
The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $8.9 billion. Any liability beyond $8.9 billion is indemnified under an agreement with the Nuclear Regulatory Commission, but subject to congressional approval. The first $200 million of liability coverage is the maximum provided by private insurance. The Secondary Financial Protection program is a retrospective insurance plan providing additional coverage up to $8.7 billion per incident by assessing retrospective premiums of $79.3 million against each of the 110 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 and NEIL III) to cover the costs of property damage, decontamination or premature decommissioning resulting from a nuclear incident. All companies insured with NEIL II and III are subject to retroactive assessments if losses exceed the accumulated funds available. The maximum potential assessment against Vermont Yankee with respect to NEIL II losses arising during the current policy year is $6.4 million at the time of the first loss and $13.8 million at the time of a subsequent loss and the NEIL III maximum retroactive assessment is $8.4 million. 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, 1994 1993 1992 (In thousands) Earnings: Operating revenues . . . . . . . . . . . $162,757 $180,145 $175,919 Net income applicable to common stock . 6,588 7,793 7,921 Company's equity in net income . . . . . 1,143 1,425 1,415 Total assets . . . . . . . . . . . . . . . $512,142 $469,770 $438,208 Less: Liabilities and long-term debt . . . . . 457,669 415,606 383,933 -------- -------- -------- Net assets . . . . . . . . . . . . . . . . $ 54,473 $ 54,164 $ 54,275 ======== ======== ======== Company's equity in net assets . . . . . . $ 9,766 $ 9,745 $ 9,731 ======== ======== ========
C. Common Stock Equity The Company maintains a Dividend Reinvestment and Stock Purchase Plan (DRIP) under which 284,153 shares were reserved and unissued at December 31, 1994. The Company also funds an Employee Savings and Investment Plan (ESIP). At December 31, 1994, there were 15,556 shares reserved and unissued under the ESIP.
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, 1992, 1993 and 1994 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, $19.9 million of retained earnings were free of restrictions at December 31, 1994.
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, 1994, $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 1995 and $1,650,000 for the years 1996 - 1999.
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 $4.793 per share until 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, 1994.
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) 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 1999 . . . . . . . . . . . . . . 3,500 --- 3,500
Non-Utility At December 31, 1994, Green Mountain Propane Gas Company, the Company's propane subsidiary, had long-term debt of $4.5 million, which was secured by substantially all of the subsidiary's assets. The annual sinking fund requirements and maturities for the next five years are: Sinking Funds Maturities Total (In thousands) 1995 . . . . . . . . . . . . . $ 600 $ --- $ 600 1996 . . . . . . . . . . . . . 1,000 --- 1,000 1997 . . . . . . . . . . . . . 1,000 --- 1,000 1998 . . . . . . . . . . . . . 1,000 --- 1,000 1999 . . . . . . . . . . . . . --- 900 900
F. Short-term Debt Utility At December 31, 1994, the Company had lines of credit with six banks totaling $39.5 million, with borrowings outstanding of $20.2 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.
The weighted average interest rate on borrowings outstanding on December 31, 1994 and December 31, 1993 was 6.4 percent and 3.7 percent, respectively.
Non-Utility At December 31, 1994, Green Mountain Propane Gas Company, the Company's propane subsidiary, had a line of credit with a bank for $2.0 million, with no borrowings outstanding.
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, 1994. 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 December 31, 1994 and December 31, 1993, were as follows:
At December 31, At December 31, 1994 1993 (In thousands) Deferred Tax Assets Contributions in aid of construction $ 5,857 $ 5,094 Deferred compensation and postretirement benefits . . . . . . 2,296 3,387 Alternative minimum tax credit . . . (829) 749 Excess deferred taxes . . . . . . . . 2,089 2,188 Unamortized investment tax credits . 2,277 2,402 Other . . . . . . . . . . . . . . . . 3,352 1,018 ------- ------- $15,042 $14,838 ======= ======= Deferred Tax Liabilities Property-related and other . . . . . $26,487 $25,090 Demand side management costs . . . . 6,457 5,841 Unamortized investment tax credits . 5,390 5,672 Reversal of previously flowed-through tax depreciation . . . . . . . . . 3,499 4,182 AFUDC equity basis adjustment . . . . 680 726 ------ ------ 42,513 41,511 Net accumulated deferred income tax (liability) . . . . . . . . . . . . ($27,471) ($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 . . . $ (798) Change in income tax related regulatory assets and liabilities. . 505 Other adjustments . . . . . . . . . . . . . . . . . . . . . . . . 17 ------- Deferred income tax expense for the period . . . . . . . . . . . $ (276) =======
The components of the provision for income taxes are as follows: Year Ended December 31, 1994 1993 1992 (In thousands) Current state income taxes . . . . . . . $ 1,205 $ 134 $ 796 Deferred state income taxes . . . . . . 70 1,225 716 Current federal income taxes . . . . . . 4,466 369 3,007 Deferred federal income taxes . . . . . (63) 4,804 2,678 Investment tax credits -- net . . . . . (283) (284) (284) ------ ------ ----- Total income taxes . . . . . . . . . . . 5,395 6,248 6,913 Amounts included in "Other income" . . . -- 1 2 ------ ------ ------ Income taxes charged to operations . . . $5,395 $6,249 $6,915 ====== ====== ======
The following table details the components of the provisions for deferred federal income taxes: Year Ended December 31, 1994 1993 1992 (In thousands) Deferred purchase power costs . . . . . $(1,310) $ 985 $ 518 Excess tax depreciation . . . . . . . . 1,387 1,417 1,648 Demand side management . . . . . . . . 1,013 2,090 799 State tax benefit . . . . . . . . . . . 39 (416) (211) Contributions in aid of construction . (657) (440) (813) Supplemental benefit plans . . . . . . 26 (198) (46) Postretirement health care benefits . . 824 (95) (158) Pine Street . . . . . . . . . . . . . . (1,915) 890 258 Other . . . . . . . . . . . . . . . . . 530 571 683 ------- ------ ------ $ (63) $4,804 $2,678 ======= ====== ======
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 as follows: Year Ended December 31, 1994 1993 1992 (Dollars in thousands) Income before income tax . . . . . . . $16,398 $16,880 $18,765 Federal statutory rate . . . . . . . . 34% 34% 34% Computed "expected" federal income taxes . . . . . . . . . . . . $ 5,575 $ 5,739 $ 6,380 Increase (decrease) in taxes resulting from: Tax versus book depreciation . . . . 327 327 357 Dividends received and paid credit . (499) (580) (597) AFUDC - equity funds . . . . . . . . (89) (93) (63) Amortization of ITC . . . . . . . . (283) (284) (284) State tax benefit . . . . . . . . . (433) (462) (514) Excess deferred taxes . . . . . . . (60) (60) (60) Other . . . . . . . . . . . . . . . (418) 302 182 -------- ------- ------- Total federal income taxes . . . . . . $ 4,120 $ 4,889 $ 5,401 ======== ======= ======= Effective federal income tax rate . . 25.1% 28.9% 28.8%
Non-Utility The Company's non-utility subsidiaries had accumulated deferred income taxes of $3.2 million on their balance sheets at December 31, 1994, largely attributable to property-related transactions.
The components of the provision for income taxes for the non-utility operations are: Year Ended December 31, 1994 1993 1992 (In thousands) State income taxes . . . . . . . . . . $123 $ (58) $(104) Federal income taxes . . . . . . . . . 444 (224) (314) Investment tax credits . . . . . . . . (45) (45) (45) ----- ------ ------ Income taxes charged to operations . . $522 $(327) $(463) ===== ====== ======
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 29.0 percent, 34.2 percent and 33.3 percent for the years ended 1994, 1993 and 1992, 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.
1994 Quarter Ended March June Sept. Dec. Total (Amounts in thousands, except per share)
Operating Revenues . . . . . . $40,611 $33,603 $36,684 $37,299 $148,197 Operating Income . . . . . . . 4,892 1,872 3,243 4,510 14,517 Net Income . . . . . . . . . . 4,040 1,237 2,653 3,072 11,002 Net Income Applicable to Common Stock . . . . . . . . 3,841 1,038 2,454 2,875 10,208 Earnings per Average Share of Common Stock . . . . . . . . $0.85 $0.23 $0.54 $0.61 $2.23 Weighted Average Number of Common Shares Outstanding . 4,537 4,564 4,605 4,644 4,588
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
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.
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 or before 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 facilitator. The council is charged with determining what additional studies may be appropriate for the site and also is planning to eventually address additional response activities.
In July 1994, the Company, New England Electric System (NEES), and Vermont Gas Systems, Inc. (VGS), entered into an Administrative Order by Consent, with the EPA, pursuant to which these PRPs are conducting certain additional studies that have been agreed to by the coordinating council. These studies constitute the first phase of action the council has decided on to fill data gaps at the site. A second phase, including tasks carried over from the first phase, additional field studies and preparation of an addendum feasibility study is expected to be performed during 1995 by the same parties under a second Order. The EPA has not required 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.
On December 1, 1994, the Company, NEES and VGS entered into a confidential agreement with the State, the City of Burlington and nearly all other landowner PRPs under which the liability of those landowner PRPs for future Superfund response costs would be limited and specified. On December 1, 1994, the Company entered into a confidential agreement with VGS compromising contribution and cost recovery claims of each party and contractual indemnity claims of the Company arising from the 1964 sale of the manufactured gas plant to VGS, and also entered into a confidential agreement with NEES for funding of work under the Order.
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. Discovery in the case is largely complete, with the exception of expert discovery which was stayed by the magistrate pending the resolution of Summary Judgment Motions filed by the Company. In August 1994, the Magistrate granted the Company's Motion for Summary Judgment with respect to defense costs against one defendant and denied it against another defendant. The United States District Judge affirmed those orders on September 30, 1994.
The Company has reached confidential settlements with two of the defendants in its insurance litigation. One of these defendants 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 other defendant provided the Company with second layer excess liability coverage for a seven-month period in 1976.
The Company has deferred amounts received from third parties pending resolution of the Company's ultimate liability with respect to the site and rate recognition of that liability. 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.
Through rate cases filed in 1991 and 1993, the Company has sought and received recovery for ongoing expenses associated with the Pine Street Marsh site. Specifically, the Company proposed rate recognition of its unrecovered expenditures between January 1991 and July 31, 1993 (in the total of approximately $4.6 million) 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 (the Department) reached agreements in both cases that the full amount of Pine Street Marsh costs reflected in those rate cases should be recovered in rates. The Company's rates approved by the VPSB on April 2, 1992, and on May 13, 1994, reflected the Pine Street Marsh related expenditures referred to above.
In a rate case filed on September 26, 1994, the Company sought recovery in rates of approximately $2.7 million in expenses associated with the Pine Street site. This amount represented the Company's unrecovered expenditures between August 1993 and June 1994 for technical consultants and legal assistance in connection with EPA's enforcement action at the site and insurance litigation. While reserving the right to argue in the future about the appropriateness of rate recovery for Pine Street related costs (and whether recovery or non-recovery of past costs and any insurance proceeds is relevant to such issue), the parties to the case have reached agreement that the full amount of Pine Street costs reflected in the Company's 1994 rate case should be recovered in rates. This agreement is currently pending before the VPSB.
Management expects to seek and (assuming treatment consistent with the previous regulatory treatment set forth above) receive ratemaking treatment for unreimbursed costs incurred beyond the amounts for which ratemaking treatment has been received. As of December 31, 1994, such amounts are approximately $845,000.
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 1995 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, 1994, as follows:
Ownership Share of Utility Accumulated Interest Capacity Plant Depreciation (In %) (In MW) (In thousands) Highgate . . . . . . . . . . 33.8 67.6 $ 9,726 $2,563 McNeil . . . . . . . . . . . 11.0 5.9 $ 8,506 $2,753 Stony Brook (No. 1) . . . . . 8.8 30.2 $10,035 $5,090 Wyman (No. 4) . . . . . . . . 1.1 6.8 $ 2,376 $1,176 Metallic Neutral Return (1) . 59.4 --- $ 1,563 $ 243 (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 1994 Retail Rate Case -- On September 26, 1994, the Company filed a request with the VPSB to increase retail rates by 13.9 percent. The increase is needed primarily to cover the rising cost of existing power sources, the cost of new power sources the Company has secured to replace power supply that will be lost in the near future, and the cost of energy efficiency programs the Company has implemented for its customers. The Company, the Department and the other parties have reached a settlement agreement providing for a 9.25 percent retail rate increase effective June 15, 1995, and a target return on equity of 11.25 percent. The agreement must be reviewed and approved by the VPSB.
1993 Retail Rate Case -- On October 1, 1993, the Company filed a request with the VPSB to increase retail rates by 8.6 percent. The increase was 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 was approved by the VPSB on May 13, 1994.
1991 Retail Rate Case -- On July 19, 1991, the Company filed a request with the VPSB to increase retail rates by 9.96 percent to cover power supply cost increases expected in 1992, the costs of upgrading and maintaining the Company's generation, transmission and distribution facilities; expenditures associated with the Company's conservation programs; and higher employee pension and health care costs. In orders dated April 2, 1992 and May 21, 1992, the VPSB approved an increase of 5.6 percent, or approximately $6.6 million, effective April 2, 1992.
The Department appealed the VPSB orders challenging, among other rulings, the VPSB's acceptance of the Company's method of treating accumulated depreciation and certain Vermont Yankee-related power costs. The Company filed a cross-appeal contending, among other things, that the VPSB had erred in reducing ratebase relating to certain demand-side management (DSM) program cost projections that had been made in the Company's prior rate case.
On April 22, 1994, the Vermont Supreme Court affirmed in part and reversed in part the VPSB orders. The Court overturned the VPSB's decision disallowing certain DSM costs. The impact of this portion of the Court's ruling resulted in the Company's other income since April 1992 being increased by $162,000. On the other hand, the Court overturned the VPSB decision in the Company's favor on an issue involving the method of treating accumulated depreciation, and on the inclusion of one item of Vermont Yankee's capital projections in power costs. The overall impact of the Court's ruling resulted in a reduction of $840,000 in the Company's revenues.
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, 1994, the present value of the Company's obligation is $10.3 million.
Projected future minimum payments under the Phase II support agreements are as follows: Year ending December 31, 1995 . . . . . . . . . . . $ 489,425 1996 . . . . . . . . . . . 489,425 1997 . . . . . . . . . . . 489,425 1998 . . . . . . . . . . . 489,425 1999 . . . . . . . . . . . 489,425 Total for 2000-2020 . . . 7,830,817 ----------- $10,277,942 ===========
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 accompanying 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 1994 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 . . . . . . . . . . . . . $ 551 $ 265 $ 1,557 Other debt service . . . . . . . . 302 286 --- Other capacity . . . . . . . . . . 1,942 405 22,655 ------ ------ ------- Total annual capacity . . . . . . . $2,795 $ 956 $24,212 ====== ====== ======= Company's share of long-term debt . $ 931 $5,101 $13,121 ====== ====== =======
(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 1994, 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 1995. The Company anticipates that purchases of tertiary energy will extend beyond August 1995, 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. During 1994 the Company negotiated an arrangement with Hydro-Quebec that reduces the cost impacts associated with the purchase of Schedules B and C3 under the 1987 contract, over the November 1995 through October 1999 period. Under this new arrangement, the Company, in essence, will take delivery of the amounts of energy as specified in the 1987 contract, but the associated fixed costs will be significantly reduced from those specified in the 1987 contract.
As part of this arrangement, the Company will purchase $3 million worth of research and development work from Hydro-Quebec over the four-year period, and is obligated to make a $7.5 million cash payment to Hydro- Quebec in 1995. The Company has the option to purchase up to $1 million worth of additional research and development work. If the Company exercises its option, the $7.5 million cash payment will be reduced accordingly. Hydro-Quebec retains the right to curtail annual energy deliveries by 13 percent up to five times, over the 2000 to 2015 period, if documented drought conditions exist in Quebec.
During the first year of this arrangement, the average cost per kilowatthour of Schedules B and C3 will be cut from 6.2 to 4.2 cents per kilowatthour, a 32% or $15 million cost reduction. Over the four-year period covered by the arrangement, unit costs will be lowered from 6.4 to 5.2 cents per kilowatthour, reducing unit costs by 19 percent and saving $34.5 million in nominal terms.
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 . . $3,782 $2,195 $15,231 $10,430 (1994) (1994) (1995-2015)* (1995-2015)* $2,726 $1,771 (1995) (1995) Annual Capacity Charge . $3,313 $1,684 $16,030 $9,966 (1994) (1994) (1995-2015)* (1995-2015)* $2,448 $1,237 (1995) (1995) Average Cost per KWH . . 2.7 cents 5.3 cents 6.7 cents 6.1 cents (1994) (1994) (1995-2015)** (1995-2015)** 2.7 cents 4.8 cents (1995) (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. Although the Company had no fixed capacity payments, it had to pay to reserve transmission from the Niagara 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, terminated 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 replaced the Company as the supplier of electricity to Bozrah, assumed responsibility for approximately 75 percent of the fixed costs of the transmission contract with Niagara Mohawk, and provided 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 arrangement was approved by FERC effective May 1, 1993. The reductions in the Company's 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.
In January 1995, CL&P and the Company signed an amendment to the contract to enable the Company to terminate the RG&E contract in January 1995, eliminating the provisions relating to the sale of capacity and energy by the Company and provided a price ceiling to substitute for the RG&E agreement price ceiling as it applies to the Company's purchase from CL&P. Additionally, contract terms for the Company's option of purchasing up to 50 MW of CL&P system power were amended to make the power available August 1995 - December 2004, and the Company's deadline for initial elections of said power was extended to July 31, 1995.
Estimated Charges Annual Transmission Reservations . . . . . . . . . $300,000
Average Cost per KWH . . . . . . . . . . . . . . . 3.3 cents (1994) 3.3 cents (1995)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
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, 1994 and 1993, and the related consolidated statements of income and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Green Mountain Power Corporation as of December 31, 1994 and 1993, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, 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 LLP
Boston, Massachusetts January 31, 1995
Schedule II GREEN MOUNTAIN POWER CORPORATION VALUATION AND QUALIFYING ACCOUNTS AND RESERVES For the Years Ended December 31, 1994, 1993 and 1992
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 18, 1995. 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 1995.
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(b)	
	There were no reports on Form 8-K filed for the quarter ending December 31, 1994.
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 30, 1995 	(D. G. Hyde, President and 	Chief Executive Officer)
	Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
/s/D. G. Hyde Chairman of the Executive Commit- March 30, 1995 (D. G. Hyde) tee, President, Chief Executive Officer and Director
/s/C. L. Dutton Vice President, Treasurer and March 30, 1995 (C. L. Dutton) Chief Financial Officer (Principal Financial Officer)
/s/G. J. Purcell Controller March 30, 1995 (G. J. Purcell) (Principal Accounting Officer)
/s/T. P. Salmon Chairman of the Board and March 30, 1995 (T. P. Salmon) Director
Director (R. E. Boardman)
/s/N. L. Brue Director March 30, 1995 (N. L. Brue)
/s/W. H. Bruett Director March 30, 1995 (W. H. Bruett)
Director (M. O. Burns)
Director (L. E. Chickering)
/s/J. V. Cleary Director March 30, 1995 (J. V. Cleary)
/s/R. I. Fricke Director March 30, 1995 (R. I. Fricke)
/s/E. A. Irving Director March 30, 1995 (E. A. Irving)
/s/M. L. Johnson Director March 30, 1995 (M. L. Johnson)
/s/R. W. Page Director March 30, 1995 (R. W. Page)
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 January 31, 1995. Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in the index on page 38 of this Form 10-K is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements, and in our opinion, fairly states, in all material respects, the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole.
Boston, Massachusetts January 31, 1995 /s/ Arthur Andersen LLP