2. The Overall Market Structure
3. Characteristics of the Separated Utility Firms
4. Pricing Services in a Restructured Industry
5. Addressing Above-Market or "Stranded" Costs
For more information, call Rosalie Genest, (802) 660-5622. Email at genest@gmpvt.com
This plan proposes creation of a new electric industry structure for Vermont and the region that offers the maximum degree of choice for all consumers while at the same time protecting the current level of safety, reliability, and access to service. The plan aims at providing these benefits without increasing the cost to any class of customers, without reducing Vermont's long-held commitment to the environment, and without breaking faith with investors or taxpayers who have financed the existing structure.
The new structure envisioned here has two distinct components: A free-market approach for generation and retail sale of electricity, and a traditional regulatory approach for transmission and distribution of electricity. New Englandís existing power pool would evolve into an Independent System Operator (ISO) and a competitive exchange for wholesale sales functioning much like a stock exchange for securities.
The distribution network within existing franchise territories would remain intact and the distribution utilities that now serve those areas would continue to do so. They would continue to own the poles, wires, switching equipment and other assets required to maintain distribution service. The distribution companies would continue to have exclusive franchises and would continue their obligation to provide access for electricity for all customers within their territories. The distribution companies also would continue to be responsible for administering cost-effective energy efficiency services that are subject to market barriers. Spending for those services and renewable resource initiatives would be set at existing levels during a transition period.
All customers would be free to choose any retail electrical energy supplier that offered service in their community, and the retail companies would be free to offer their products and services in any state in which they were certified to operate. Customers who did not choose a new energy supplier would continue to be served by the retail company that was affiliated with the utility that served the customer before the restructuring. This company would continue to be obligated to provide a basic service package to any customers who could not obtain electricity from a retail company of their choice.
This initiative has four purposes:
The timing of the restructuring is critical. If Vermont moves too slowly, Vermont consumers, particularly business customers, will be denied an advantage given to their competitors in other states, and Vermontís electric utilities will lose their chance for early entry into the open market. The state as a whole will lose in the contest for economic development. If Vermont moves too quickly, before retail competition opens up in other areas, the state could suffer from becoming an economic guinea pig.
This plan proposes a timetable that requires the opening up of competition for a substantial portion of the region at the same time, and would follow this benchmark schedule:
This proposal by GMP incorporates the work throughout 1995 of the Vermont Competition Roundtable. The 14 principles adopted by the Roundtable in August 1995, are fully and faithfully advanced by this proposal, including the commitments to reliable and safe service, universal access, customer choice, low-income consumers, environmental protection, energy efficiency and renewable resources, and to honoring of financial obligations of utilities arising from decisions made under historic regulatory and legal principles.
Many proposals for restructuring of the electric energy industry have been developed over the past few years, including proposals specifically for New England. The New England Electric System (NEES) has put forward a regional plan that includes many important concepts and details that have been incorporated into this plan.
GMP has approached the need for restructuring from the perspective of a comparatively small utility, in keeping with Vermont's position as a relatively small part of the New England market. Considerations of scale do not alter any fundamental aspects of restructuring, but relative size is a factor that must be considered in the interests of fairness and viability of the enterprises that inherit the duties, obligations, and opportunities of the historic integrated public service utilities.
Following is a summary of the key concepts detailed in the body of this proposal:
Those functions of the electric system that are most efficiently provided by a single provider--transmission and distribution of electricity--would continue to be regulated.
Other functions--generation and sales of electricity and related services--would be open to competition.
Vertically integrated utilities, which now undertake all functions of electric service, would be separated into their component parts, as follows:
Unregulated generation companies (GenCos) would produce electricity and sell it at wholesale through individual contracts or through the Power Exchange (see below).
Regulated transmission companies (TransCos) would transmit electricity from power plants to local distribution companies. Transmission functions in Vermont are largely provided by the Vermont Electric Power Company (VELCO).
Regulated distribution companies (DisCos) would have franchise territories with the obligation to connect customers in that territory, as is the case today. The distribution companies would provide open access to their distribution grid at non-discriminatory rates, bringing electricity to retail customers and providing metering services for some customers. They would be responsible, as they now are, for the planning, construction and operation and maintenance of the poles, wires and associated electrical system. They would also administer state-mandated efficiency programs (discussed below in Section 6).
Distribution companies would be set up as distinct companies, if possible, but could be owned by a common parent company. They would be functionally separated from generation and retail companies, with no sharing of operating personnel and appropriate limitations on the flow of sensitive information. These requirements would prevent a distribution company, with monopolistic control over its territory, from favoring an affiliated retail company.
Retail energy companies (RetailCos) would sell electricity and other energy services to industrial, commercial and residential customers. Retail companies would also be responsible for metering not provided by the distribution companies, consolidated billing of electrical system functions, collection, and other customer service activities like market-based efficiency services and products and emergency back-up power.
An independent entity would coordinate regional generation and transmission to ensure the non-discriminatory access, safety and reliability of the electric system. This ISO would perform many of the functions that the New England Power Pool (NEPOOL) does today.
A Power Exchange would be developed to create a short-term market for electricity sales, in much the way that the stock exchange is the marketplace for securities transactions.
Rates for distribution would continue to be set by State regulation, either the traditional cost-of-service approach or an innovative, performance-based approach.
Prices for generation and energy sales would be set by the marketplace, just as they are in other unregulated industries.
The price of electric service would be divided into its component parts:
A price for energy, set by the marketplace.
A price to cover the cost of access to the electrical grid, set by regulation. This access charge would include a fee for the recovery of stranded costs (see below) and a fee to cover the cost of mandated energy-efficiency and social programs (discussed below in Section 6). Both of these fees would be set by regulation.
Every customer would be entitled to a Basic Service Package, of electricity, at a price based in part by regulation and in part on the lowest cost electricity available in the market.
The term "stranded costs" refers to investments that a utility made prudently, but that it would not be able to recover fully in a competitive market. Such investments include power contracts and generation stations with costs above the market, and nuclear plant decommissioning costs. These costs would be calculated and recovered through the access charge during a transition period from regulation to competition. The amount of stranded costs would be established by an auction of generation stations and power contracts.
The distribution company would continue to fund efficiency programs and renewable energy research and commercialization. During a transition period, it would fund those programs at a level consistent with that utility's current level of funding for efficiency programs. Distribution companies would also fund a program to provide subsidies for electricity service to low-income customers. The costs of these programs would be included in the access charge.
GMP supports the development of a market that would provide retail customers with an opportunity to purchase electricity from specific suppliers of generation or from a spot-market through the creation of a Power Exchange. The structure of this model is shown in Figure 1.
Under this plan, individual utilities would be separated into their competitive and franchise components. A complete description is contained in Section 3. Utilities with generating assets or purchased power entitlements, which would compete in an open and competitive market, would be required to separate that generation into unregulated "GenCos." Transmission and local distribution activities, which can be provided more cost effectively by one firm, rather than multiple providers, would be separated into "DisCos" and "TransCos." These services might be provided by a single company or separate companies. In addition, a regional ISO would coordinate the activities of the TransCos and GenCos to ensure non-discriminatory access and the safety and reliability of the region's transmission and distribution systems. This ISO would perform functions similar to those provided today by NEPOOL. In fact, with relatively minor adjustments, the existing NEPOOL structure should be able to begin implementation of this plan, while a Power Exchange mechanism is developed.
There also would be many retail service providers, called "RetailCos," providing customers with electricity, energy efficiency/demand-side management (DSM) services, and other customer services. RetailCos would be certified by the states in which they operated. Owners of generation could set up their own RetailCos to sell directly to customers. RetailCos could also include power marketers, brokers, aggregators and other providers. Utilities would be required to separate their sales activities from their regulated DisCo activities, and compete for customers equally with other independent RetailCos.
Under this market structure, RetailCos would supply electricity to customers based on direct contracts with generation suppliers (sometimes called "bilateral" contracts) and/or the short-term market that is created by a regional Power Exchange. The Power Exchange would act as a market clearinghouse in much the same way that the Chicago Board of Trade handles commodities and the New York Stock Exchange facilitates a market for stock sales.
Generation suppliers(including independent brokers and marketers(could sell generation into the Power Exchange, rely exclusively on direct (bilateral) contracts with buyers, or to both. Bids into the Power Exchange would be for power to be supplied for specific hours of the next day. Based on the bids received and the forecast of the demand for power during those hours, the Power Exchange would establish and publish a market price for power the next day for each hour. This price (spot market price) would be the price of the last successful bid. All suppliers into the Power Exchange would be paid this spot market price. That way, the correct (efficient) set of price signals to suppliers would be sent to customers, encouraging generation capacity additions only when the market saw a need for them. The Power Exchange also would provide the correct price signal to suppliers of alternative energy sources or energy services, such as DSM, self-generation and co-generation, which will encourage economically efficient decisions by suppliers and customers. This method of establishing a spot market is currently used in the United Kingdom.
At this stage, generators may have commitments to supply power into the spot-market pool, as well as contracts for different time periods with individual customers through their respective RetailCos. In Figure 1, for example, one of the many GenCos might contract to supply an industrial firm 5 MW of power 24 hours per day for the next year. That would be an example of a bilateral contract.
To ensure that the regional network of transmission lines owned by the TransCos deliver power reliably and without discrimination, an independent entity would coordinate operations of the Power Exchange and control the transmission system. This is the role of the ISO. The ISO would manage all of the physical flows of power in a manner similar to the current operations of the NEPOOL, the existing regional entity that coordinates power flows throughout New England. To ensure the safety and reliability of the system, the ISO would set rigorous standards for non-discriminatory access, reliability, reserves and power quality, much as NEPOOL now addresses operating reliability and provides payments to generators for power needed to maintain system flexibility and stability (e.g. spinning reserves, voltage support, etc.) These standards would have to be met by the TransCos and GenCos, just as is done today for NEPOOL members.
The Power Exchange will provide clear price signals between suppliers of electricity and ancillary services and buyers, at the lowest reasonable cost. These price signals will be provided through the development of a bid-price resource pool that establishes a clear spot market price, plus direct bilateral contracts between buyers and sellers who wish to hedge risks of future price uncertainties. (The transition to this structure is discussed in Section 7).
The adoption of a voluntary bid-based dispatch system and the deregulation of the price of generation create the potential for anticompetitive behavior and market power by large suppliers of generation. This issue is addressed in Section 7.
The various local DisCos would deliver power to ultimate customers. For example, the GMP DisCo would maintain its existing exclusive distribution franchise and ensure that this system operates safely, efficiently and at the least reasonable cost. The DisCos would repair lines and respond to power outages, just as they do today. Because DisCos would retain their exclusive franchises, they would remain regulated.
Many aspects of the wholesale sale and transmission of electricity, the GenCo and TransCo functions, are regulated by the Federal Energy Regulatory Commission (FERC), rather than individual State utility commissions. The FERC has initiated changes concerning market structure that are consistent in concept to what is described here. In particular, wholesale sale of electricity by unregulated utilities may be based on market prices, rather than costs, for those companies that provide non-discriminatory, unbundled transmission service.
In the restructured environment, formerly vertically integrated utilities will have been separated into their competitive and franchise components. Although not required, some utilities may leave the generation business to third parties or spin-off entirely new companies. At a minimum, however, utilities will be required to functionally separate generation and retail sales from transmission and distribution.
The GMP Plan calls for separation of vertically integrated utilities into separate DisCo and RetailCo units. DisCos would continue to be regulated and would provide transmission and distribution functions<1>, limited metering services, and administration of core DSM and renewable resource programs. RetailCos would be deregulated and would provide all other competitive services. These services are described in more detail below.
This separation is intended to reflect the basic distinction between those functions (transmission and distribution) that are more efficiently provided by a single firm and those (generation and retail sales) that can be efficiently provided through competitive forces. Separation is necessary in order to prevent DisCos from favoring their affiliated RetailCos, to the detriment of competing Retailcos.
The core services to be provided by DisCos include construction, operation and maintenance of the transmission/distribution system, including poles, wires, substations, transformers and service drops. These services involve significant economies of scale and therefore are more efficiently provided by a single entity. It would be impractical and uneconomic, for instance, to construct and maintain two or more sets of wires and poles.
Although the GMP Plan would not require separate entities to provide transmission and distribution services, this separation would not be prohibited. In Vermont, for instance, almost all transmission service is now provided through the Vermont Electric Power Company (VELCO), which is owned by many of the 22 Vermont distribution utilities. In addition, the larger Vermont utilities provide subtransmission (lower voltage transmission) service to the smaller utilities. Under GMP's proposal, no change would be required in the ownership of transmission assets or the provision of transmission service.
DisCos also would have to provide or obtain the generation or controllable load necessary for local area control and related functions. This would require that certain local generating facilities (or interruptible load contracts) be operated to maintain the integrity of the system regionwide, regardless of whether there was a specific retail contract for the electricity generated.
In addition to their transmission and distribution functions, DisCos also would be responsible for certain DSM and renewable resource programs. These programs, which are described in more detail in Section 6, primarily would involve distributed utility planning activities, "core" DSM programs that could not be sustained in the competitive marketplace because of competitive "market barriers," and programs to promote the commercialization of renewable resources. With respect to core DSM programs and renewables, the DisCo would administer, but generally not implement, these programs. DisCos will administer these programs because their level and design will continue to be provided under regulatory oversight, and because the funding mechanism is through an access charge related to distribution
service. Least-cost implementation of the programs will typically be assured by soliciting bids and implementation by the successful bidder. The same allocation of functions will apply to renewable resource programs, which are described in Section 6.
DisCos also would be obligated to provide metering services for certain customer segments, including meter installation and maintenance and meter reading. Meters can be purchased in the competitive marketplace. From this perspective, metering might be thought as a competitive, and therefore a RetailCo, function. Yet, for small customers with meters that must be read at the customer's location, meter reading poses a significant barrier to competitive entry. Unless small customers are aggregated by geographic location, the cost of meter reading may become a significant portion of the total cost to serve small customers. For this reason, DisCos should be required to provide meter reading service for those customers who are not telemetered, until it is demonstrated that there are no significant meter-related barriers to entry for service to low-use, non-telemetered customers.
DisCos also would be responsible for disconnection and reconnection. This activity also includes significant work in the field and therefore has similar market characteristics to metering. Disconnection also involves safety concerns that are more appropriately handled by the DisCos.
All of the other services now provided by vertically integrated utilities, except those identified above, would be supplied by the competitive market. Although individual services might be provided by separate entities depending on the evolution of the competitive market, for purposes of discussion, we assume all of these services will be provided by RetailCos.
The primary functions of the RetailCo will be selling electricity (either by owning their own generation units or contracting for power from other generators), billing and collection and other activities associated with the sale of electricity, such as marketing, customer service activities (DSM, power quality, emergency backup power, etc.). The market will determine whether purchases are made through the Power Exchange or through direct contracts with generation owners.
Separation of competitive generation activities from transmission and distribution activities is widely understood to be necessary for "meaningful" competition. This separation is necessary to guard against provision of distribution services by DisCos in a manner that favors their affiliated RetailCos. With respect to retail sales, several considerations support the separation proposed by GMP. As with generation, there is no basis for concluding that significant long-term barriers to entry remain for retail sales functions. Clear separation of these functions from the regulated distribution function will assist the advent of competition by breaking the link in the customer's mind between traditional franchised utilities and competitive providers of energy services.
Although these considerations support a clear separation between the distribution and sales functions, the dividing line is not identified easily. As described above, certain meter-related services would continue to be offered by the DisCos for the time being. In addition, it is important that customers have direct access to the DisCo for purposes of reporting outages and other distribution-related matters.
Separating DisCos and RetailCos requires the plan to address the organizational requirements that should be imposed and the level of interaction that will be permitted between them.
There are three widely-recognized potential methods of organizational separation between the DisCo and RetailCo functions: (1) separate business units within the same corporation or other organization; (2) separate corporations jointly owned by the same entity or entities; or (3) separate corporations with separate ownership.
GMP proposes the second option: separate DisCo and RetailCo corporations with no prohibition against common ownership of both. Corporate separation would assist in monitoring the limitations of the relationship between the DisCo and RetailCo described below, while preserving some of the economies of scale inherent in integrated organizations. It would also permit a clearer distinction between regulated and unregulated activities. Full divestiture should not be required (although it would be an option for any utility and may be necessary to address market power issues in some cases), because the costs and the practical difficulties associated with divestiture may outweigh the competitive benefits. Economies of scale would be lost and transaction costs could be significant.
In addition, GMP does not propose that the generation and retail sales functions necessarily be separated, because both functions inherently are competitive in today's marketplace. Vertical integration does not appear to pose significant barriers to entry in either the generation or retail sales market. It should be noted that the issue of horizontal market power in the generation market must be addressed further, as described in Section 6.6.
Separation into affiliated corporations would, in all likelihood, result in a holding company with DisCo and RetailCo subsidiaries. In the case of municipal utilities, this requirement would be implemented by creating separate municipal departments for the DisCo and RetailCo functions.
The requirement of corporate separation should be relaxed where it would be impractical. Corporate separation could impose an unnecessary level of hardship for some smaller utilities, where efficiencies gained from integration can be more pronounced. Generic rules should be developed to assure equitable application of this exception.
In addition to size, there are other reasons why corporate separation might be impractical. In many cases (including GMP's), bond indenture provisions require the bondholders to agree in most circumstances before a transfer of assets can be made to another corporation. Many contracts prohibit assignment to another corporation without consent of the other party. In these cases, the utility should be required to make a good faith effort to secure the necessary consents. Similarly, to the extent that corporate separation renders the owner of the separated corporations subject to extensive additional regulation (such as Securities and Exchange Commission under the Public Utility Holding Company Act of 1935), corporate separation should not be required.
For separation to be meaningful, there must be limitations on the relationship between the DisCo and RetailCo in several areas. These requirements are needed to prevent the DisCo, with control over facilities, from favoring its affiliated RetailCo. First, there should be no sharing of operating personnel between the DisCo and RetailCo, and minimal sharing of assets. Operating personnel include employees having day-to-day responsibilities for planning, directing, organizing or carrying out the core functions of either the DisCo or the RetailCo. The separation requirement therefore would not extend to management of operating employees, nor to many support activities, including legal, financial and other common functions. Assets should be shared only to the extent that duplication can be demonstrated to be uneconomic. It might be unduly expensive, for example, to duplicate the computer system that an integrated utility currently uses for tracking and billing of both generation and distribution costs. In these circumstances, one entity would own the asset and charge the other in the manner described below. In many cases, the asset might be owned by the holding company, with costs assigned to each subsidiary.
Second, there should be strict limitations on the provision of information by the DisCo to the RetailCo. The DisCos will be in possession of commercially valuable, non-public information by virtue of its position in providing distribution services. A DisCo cannot be permitted to share this information only with its affiliated RetailCo, to the detriment of competing RetailCos. Therefore, a DisCo should not be permitted to disclose to its RetailCo non-public information received from another retail company or potential retail company. Similarly, certain information concerning transmission and/or distribution of electricity must be publicly available at the time it is provided to the RetailCo.
Third, the costs associated with DisCo and RetailCo functions must be identified and tracked separately to prevent inappropriate shifting of costs between the DisCo and the RetailCo. This provision requires each to keep separate accounting books. It means also that costs for any activities (labor or assets) shared between the units must be allocated. Under the current system of cost allocation for GMP, costs for most activities are allocated on a net book basis. The cost of a computer system serving both units, for example, would fall into this category. This methodology continues to be appropriate in a restructured environment.
Once a DisCo and RetailCo are separated, the services provided by the RetailCo would not be subject to traditional cost-of-service regulation. Instead, market forces would replace the function of traditional regulation. RetailCos would be subject to certain consumer protection obligations, which are described in Section 6.5.
The DisCo would continue to be subject to full cost-of- service regulation, however, for the services it provides. Price regulation could take the form of price caps or some other type of performance-based regulation. In addition, the DisCo would be required to offer its services on a non-discriminatory basis to all qualifying purchasers, as part of its "obligation to connect."
The DisCo would retain a franchised service territory in which its distribution service would be exclusive. No customer would be permitted to receive electricity from any source unless distribution service was purchased from that DisCo, with the exception of on-site generation that does not require interconnection.
Currently, GMP's retail rates are set based on traditional ratemaking principles: economic efficiency, fairness and adequacy. These principles are meant as ratemaking guides for a vertically integrated utility that is "affected with a public interest," in return for an exclusive franchise. Under the current industry structure, price determination begins with setting a utility's overall revenue requirements, which are based on the costs of providing service to all of the utility's customers, including an adequate rate of return for stockholders. The second step is to allocate these revenue requirements across different classes of customers, generally broken out as residential, commercial and industrial. Once the overall costs are allocated to the different customer classes, rates for each class are determined based on the three principles mentioned.
The economic efficiency principle mentioned above means that marginal costs (the cost to produce the next kilowatthour of electricity) should form a benchmark in setting rates. At present, marginal costs are less than the average costs associated with utility's total revenue requirement, primarily due to the current power surplus. As a result, in GMP's most recent rate design case, retail rates were changed first, to reduce the usage charge to a level closer to marginal cost and, second, to increase the fixed monthly charge. In a restructured environment, these traditional ratemaking principles will continue to be applicable for DisCo provided services.
Utility services also are bundled in today's market. Customers pay one price for a variety of services, including the costs of transmission, distribution, power quality (i.e. the assurance that power is delivered at the correct voltage levels, is relatively free of voltage spikes and meets other criteria), capacity (assurance that the utility will maintain reserve generation to meet customer demand for electricity at peak times) and energy.
In a restructured environment, prices will be unbundled. Services that are provided by the DisCo (including transmission and distribution) must be separated from those that are provided by the RetailCo (including generation and retail services). Competitive services will be priced by the market, just as they are in other unregulated industries.
With unbundled prices, the DisCo would charge for distribution service, metering and related services and for access, including recovery of stranded costs (discussed in Section 5), DSM/renewables, low-income funding and funding for State regulation. DisCo charges would be submitted to the RetailCo. The RetailCo would charge customers for the cost of electricity, for TransCo provided transmission, for DisCo charges and for other services associated with retail sales.
As noted above, the access charge is intended to recover stranded costs, DSM/renewables, low-income funding and funding for State regulation. Consistent with current ratemaking principles, an increasing proportion of these costs should be recovered on a fixed monthly basis, rather than through the usage charge. When access costs are recovered as much as possible through a fixed charge, customers will receive more accurate price signals in the competitive generation market and will be able to make more informed choices about their electric and related energy services. By placing fixed costs into the access charge, decisions to self-generate or switch to other fuels because electricity charges are higher than the true costs to serve the customer (uneconomic bypass) will be less frequent, and greater economic efficiencies will result. This trend will be increasingly important, as competitive pressures will make it more difficult to recover fixed costs on a usage basis.
The price structure must be fair, especially for low-income and low-use customers. These concerns can be addressed through targeted mechanisms. For example, protection for low-income customers can be provided through a surcharge/rebate system that ensures these customers will have sufficient funds to pay their bills, as described in Section 6. For low-use customers, it should be possible to design pricing schedules that recover access charges to some extent on a usage basis. Thus, for low-use customers, the access charge will balance economic efficiency and predictability of recovery with bill stability. This plan proposes that the allocation of DisCo costs among the residential, commercial and industrial classes be based on traditional rate-setting principles.
Another issue that has been raised is whether access charges relating to the recovery of stranded costs should be imposed on new customers. For reasons of fairness, these costs should be shared by new customers. Doing so will be consistent with past utility practices of sharing the costs of new facilities among all customers, rather than attempting to assign "responsibility" for new loads to individual customers.
As more customers are added, the stranded cost portion of the access charge should decrease for each individual customer. The access charge levied by the DisCo will be revised in regular proceedings before regulators, in the same manner that other DisCo charges will be reviewed. The assignment of identified stranded costs to different customers and the amount of those assignments will also be addressed by regulators.
One of the most complex issues associated with industry restructuring is the treatment of previously incurred utility investments and purchases that a utility will not be able to recover in a competitive market. For example, a generating plant built by the utility may produce power today at an average cost of 5 cents per kilowatthour. However, if the market price of power is 4 cents per kilowatthour, that plant will not be competitive.
Above-market costs are a large problem today in large part due to the existing surplus of generating capacity in the region. Surplus electricity is currently sold in wholesale markets at a price just above short-run marginal cost.
Above-market costs reflect not only specific generating resources contracted for or owned by utilities, but also other regulatory and public policy requirements. For example, utilities must collect decommissioning expenses for nuclear power plants. They must provide demand-side management services that cannot be supported in markets today. They must provide for the needs of low-income customers.
Equity and economic efficiency require that utilities be allowed to recover all of their stranded costs.
Under the regulatory compact, utilities were required to undertake certain long-term investments to meet the future electricity needs of their customers. Many utilities invested in large generating plants, intended to exploit economies of scale (i.e. lower average costs) that such plants offered. This strategy made sense in an era when electricity demands were projected to grow steadily for many years. In addition, the Public Utilities Regulatory Policy Act of 1978 (PURPA) sought to encourage the development of alternative generation that would reduce the nation's dependence on oil. To encourage that development, PURPA provided for payments to these independent power producers (IPPs) at prices that assumed sharply rising oil prices in the future.
Many factors have combined to make the situation in which the market price for electricity is below the cost of these resources. The economy entered a recession, demand grew less than forecasted (due in part to DSM) and new, cheaper generation sources became available.
These changed circumstances do not justify denial of stranded cost recovery. These costs were incurred in connection with an obligation to serve all customers in a franchised monopoly environment. Denial of stranded cost recovery under these circumstances would be unfair.
Many utility stockholders and bondholders purchased their stocks and bonds as relatively secure investments, based on the continuation of cost-based, monopoly regulation. To require these stockholders and bondholders to bear significant losses because of a change in laws would be inequitable. For municipal utilities, the "stockholders" are local taxpayers and for cooperative utilities, they are the customers.
Shifting these costs to utility stockholders and bondholders or, in the case of municipal utilities, to local taxpayers, would also reduce economic efficiency, not improve it. The reason is that reductions in the price of electricity are not the same as improvements in productivity and efficiency. Customers who shift utility costs from themselves to others may lower their costs, but do nothing to improve the overall productivity and efficiency of generation markets.
Efficiency losses can arise if investors fear that the "rules of the game" will be changed midstream. Investors who perceive greater long-term risks associated with recovering their investments will expect higher returns to compensate them for the increased risks. This will lead to higher costs of capital. That in turn will increase overall electricity costs.
By ensuring that stranded costs are recoverable, inefficient competition is less likely to occur. An efficient market should benefit everyone, not just the few who have shifted costs to others.
There are four categories of potentially stranded costs. These are above-market generation and purchased power costs, regulatory assets such as deferred expenditures for DSM investments, mandated IPP contracts, and nuclear plant decommissioning costs.
GMP owns few generating assets. It owns eight small-hydroelectric facilities with a total capacity of about 36 MW and several diesel and gas turbines, used for meeting peak loads. In addition, GMP has partial ownership in three fossil-fuel plants: Wyman 4, which is oil-fired; Stony Brook, which uses natural gas and oil; and the McNeil Generation Station, which is primarily a wood-fired steam facility. GMP also shares ownership in the Vermont Yankee Nuclear plant.
The majority of GMP's generation is supplied under contract. The major contracts include the Company's long-term purchases from Hydro-Quebec and (until 1998) purchases from the Merrimack plant in New Hampshire. (Technically, GMP's share of output from Vermont Yankee is also a purchased power contract.)
Under the guidelines of PURPA, GMP has been required to purchase the output of numerous qualifying small power plants. The electricity generated by these plants is sold through the Vermont Power Exchange (VPEX). Currently, the average purchase price for this generation is just over 10 cents per kilowatthour and is forecast to increase to 12.5 cents per kilowatthour by 2003. These purchases account for the majority of GMP's remaining above market costs associated with generation.
Regulatory assets consist of costs incurred in part where recovery from customers has been postponed due to regulatory decisions. The majority of GMP's regulatory assets are deferred expenditures GMP has made to acquire DSM resources.
Part of the stranded costs associated with nuclear power plants include future decommissioning costs. Currently, GMP collects a small surcharge from customers that is allocated to a special fund to meet predicted future decommissioning costs. The surcharge is designed to recover decommissioning costs over the lifetime of a plant. Thus, if a plant were shut down today, there would be a shortfall of funds available to meet anticipated costs of its decommissioning, which would have to be collected from customers.
Regardless of the overall lifetime of the plant or its future ownership, these decommissioning costs will have to be paid. Future decommissioning costs are subject to much uncertainty, and all utilities that own or share ownership in nuclear plants, including GMP, must face this issue.
Estimating and allocating stranded costs poses a number of difficulties. Methods for determining stranded costs fall into two broad categories: 1) regulatory or administrative approaches, and 2) market-based approaches. Regulatory and administrative approaches can be distinguished further into two sub-methodologies: 1) A "bottom-up" approach that calculates stranded costs by individual resource and category; 2) A "top-down," or "lost-revenues," approach that calculates the difference between customer revenues under market prices and revenues under existing cost-of-service regulations.
The bottom-up approach estimates the costs associated with each individual resource and assigns those costs to different customer groups where possible. Trying to reconcile the specific costs of individual generating and contract assets, can be difficult and time-consuming.
The top-down or lost-revenues approach calculates an estimate of what revenues would be under the existing system of cost-based regulation and compares that with actual or forecasted revenues based on market prices. The problem with this approach is that it is difficult to assign stranded costs to individual resources or contracts. Lost revenues can be estimated either before or after the fact. If they are determined before the fact, an administrative procedure would be used to forecast future market prices and costs over some time horizon. The difference would then equal lost revenues. While this deals with stranded costs immediately, predicting future costs and prices will be fraught with uncertainty. Alternatively, lost revenues can be calculated after the fact. For example, at the end of each year, the average market price would be determined and compared with total costs under a cost-of-service regime. The difference would then be trued-up through a regulatory process. The problem with this after the fact approach is that it requires ongoing regulation of a competitive market and thus may hinder competition. Hybrid approaches -- using actual market prices and forecasted costs, for instance -- are also possible.
The primary market-based approach is an auction; generation assets (plant or contracts) are valued directly by putting them up for sale, much as the value of a house is determined when it is sold. It measures directly the market value of the involved assets. With the auction approach, there is no need for ongoing regulation to determine revenues and costs, because the market will have taken care of that determination.
While this approach is straightforward in theory, there are several practical issues that must be addressed. First, there must be protections to assure against an undue market concentration of generation assets. This issue is addressed further below.
Second, there is the problem of market valuation. If thousands of megawatts of generation are sold at the same time, the result may be depressed prices and higher stranded costs, just as the price of housing falls when there is a glut of homes on the market and few buyers.
Third, potential bidders will require some minimum amount of information in order to make the auction successful and be able to raise the capital necessary to finance a winning bid. Potential bidders who have little access to information may discount their bid prices and therefore increase potential stranded costs, much as a home buyer probably would offer a lower price to buy a house sight-unseen.
Fourth, an auction approach raises questions about allocating the risks of future price shocks. Unforeseen events may require customers to pay higher market prices for electricity than currently anticipated, even though they will be paying the original stranded costs based on current expectations.
Fifth, bond indenture provisions and power purchase contracts may preclude the transfer of utility generation assets or contracts without third party consent. Similarly, the Nuclear Regulatory Commission (NRC) will require assurance that any purchaser of a nuclear unit will continue to adhere to safety requirements. Finally, there are restrictions on acquisition of certain generation, based on the identity of the purchaser. Preference power from the New York Power Authority (NYPA), for instance, cannot be sold to investor-owned utilities.
Assuming that the practical concerns can be addressed successfully, GMP recommends the auction approach as the preferred method for determining each utility's stranded costs. The benefits of an auction approach which would provide a more accurate, market-driven calculation of stranded costs, in all likelihood outweigh the practical problems.
In principle, all generation resources and power contract resources (the first and second category, described above) can be auctioned off. Stranded costs associated with deferred DSM expenditures and other regulatory assets should be added to the DisCo access charges. There appear to be special circumstances associated with the fourth category costs, decommissioning nuclear power plants. Given the uncertainty of decommissioning costs, linking a sale of nuclear plant generation with an obligation to assume decommissioning costs could drive away all potential bidders. To account for this, GMP recommends that, if feasible, the generation from nuclear plants be auctioned off separately from the decommissioning obligation. Under the proposal, decommissioning obligations would remain with the DisCo and the cost would be recovered through the access charge. The amount of the surcharge should be calculated on the assumption that existing decommissioning cost estimates are valid. However, as decommissioning cost estimates change, so should the surcharge collected, to assure that the appropriate level of decommissioning funds are available.
An auction would allow all interested and qualified parties to bid on any individual generating asset, whether a specific plant or a contract, to determine the market value of all generating assets. The bidding mechanism must afford a reasonable opportunity for utilities that intend to remain in the generation business to retain these assets. Continued ownership of generation assets would take advantage of utilities' expertise, efficiencies of integration and economies of scale. It must also be recognized that only RetailCos affiliated with DisCos will be obligated to offer the Basic Service Package (described in Section 7.1). Failure to afford affiliated RetailCos a reasonable opportunity to retain generation assets would be little different from forced divestiture of these assets, which is rejected for the reasons described in Section 3.3. As a consequence, affiliated RetailCos should be provided with a right of first refusal that will allow them to match the highest auction bid received.
No entity, however, should be able to acquire so much generation that it can exercise undue market power and inhibit the workings of an open, competitive market in generation. GMP recommends that all potential bidders be limited to acquiring generating assets below a maximum percentage of the region's existing generation capacity.
Another concern is ensuring that enough information is available to bidders. Otherwise, potential buyers will tend to lower their bid prices. One way to correct this problem is to design an agreed upon package of basic plant or contract information that would be compiled by independent auditors who would make this information public to all bidders.
A final concern relates to obtaining assurance that a single market-determined stranded cost calculation does not turn out to be unfair, as a result of changed circumstances. Under the GMP Plan, local distribution customers will assume the obligation through the DisCo access charge to pay for stranded costs, the amount of which is set by the auction. If, for instance, there is an unanticipated market change in the future that greatly changes the market price of generation, such as a future OPEC oil embargo, one could argue that customers would pay "twice" for some generation: first, they will have paid for the stranded costs that were determined initially, when the value of generation was lower; second, they will be paying a price for their electricity that is higher than the price implicit in the auction sale. Customers will benefit if the value of the assets in the future is below the price set by the auction, because the amount of stranded costs to be recovered will not be increased. Thus, while this risk is symmetrical, customers will have borne the risk from auctioning off generating assets at values below those reflected by subsequent events.
To address this issue, an "insurance" policy to protect against this risk could be purchased when individual generating entitlements are sold at auction. This insurance would allow the local DisCo associated with the former utility owner of the generation (or contract) to reward its customers in the event of significant increases in the market value of the sold assets. In essence the insurance company would make payments to the DisCo equal to the difference in the price of power actually sold by the auctioned asset and the price of power implicit in the auction price. <2> These insurance payments would reduce the stranded cost portion of the local access charge, offsetting the increased price of electricity. The relationship between the insurance payment and the increased energy prices will depend upon the similarity between the generation assets sold and the generation assets serving these customers.
Bids for insurance would be solicited at the time the auction took place, would be provided by a creditworthy company (the asset purchaser, if qualified, or a third party), and would be paid for by the DisCo associated with the seller of the generation. Regulators could determine whether the cost of the insurance was worth the price. <3>.
There are many practical issues associated with this concept. The reasonable maximum price for the insurance and the duration of the insurance policy must be determined. The appropriate "trigger" mechanism for a specific insurance policy must also be selected, which could be the market price of electricity or another index that reflects the market value of the generation sold.
The time frame for recovery of stranded costs involves balancing the benefits of a short recovery period against the increased access costs that accelerated recovery would require. GMP does not propose a change in the periods implied under current ratemaking procedures, although changes could be made through the regulatory process.
The Principles adopted by the Vermont Competition Roundtable call for the preservation of the social benefits provided under the current system. These social benefits include maintaining certain demand-side management programs, ensuring environmental protection, providing a "safety-net" for low-income and other economically disadvantaged customers, and ensuring that all customers will have access to a supplier of electricity at a reasonable price. GMP's restructuring proposal is intended to preserve these social benefits, while providing the benefits of a competitive marketplace.
Establishing a competitive environment for sale of energy to customers through restructuring will provide new opportunities for DSM investment to occur within the unregulated marketplace and should remove some market barriers to economic DSM investment. DSM investment decisions will be based on RetailCo charges, rather than the lower wholesale cost of power. RetailCos will have an economic incentive to work with their customers to reduce costs and increase efficiency.
Examples of such market barriers today include customer lack of access to capital and commercial landlord-tenant relationships that typically fragment benefits of DSM investments. Some new market barriers may also be created by restructuring, and some existing market barriers will probably remain in a restructured system - perhaps indefinitely.
It will not be possible to understand the full impact of restructuring on DSM investment until both customer behavior and competitive service suppliers have adapted to this new environment. Thus, to ensure that the benefits of economic DSM investment are retained in a restructured electric utility system, it will be necessary to maintain some mandated utility DSM investment at least through a transition period.
GMP proposes that the DisCo be responsible for providing mandated DSM investment through the transition period and collecting the funds to support this investment, all subject to appropriate Public Service Board (PSB) oversight. Delivery of mandated DSM investment generally should be accomplished by third parties (rather than by DisCo staff) and through a competitive bidding process wherever practical to do so. Any non-regulated party would continue to be free (as it is today) to provide DSM services.
During the transition period GMP envisions continuation of DSM and renewable energy resource programs, at a budget level consistent with each utility's current spending level. In GMP's case, for example, the current spending level is approximately $4 million annually. The transition period should coincide with the period during which there are substantial market barriers for core DSM programs.
In addition to evaluating certain DSM programs designed to reduce electricity consumption, DisCos will have an ongoing role to provide distribution capacity in the most cost-effective way. Despite the push towards full competition, the existing economies of scale associated with transmission and distribution services will remain for the foreseeable future. Regardless of where a customer ultimately purchases electricity, that electricity still will have to be delivered over the local DisCo's distribution system. DisCos will have to ensure that their distribution systems provide the reliability and power quality customers need.
DisCos will face other concerns from customers and regulators. There is increasing reluctance to build new transmission and distribution lines, or even upgrade existing lines, because of their expense and environmental footprints. Thus, all local utilities are confronting the need to manage their existing distribution systems better.
Distributed utility (DU) planning is one solution. DU planning can address issues of resource choice and control, timing, and environmental degradation. Development of DU resources will, in essence, stand the "traditional" utility planning method on its head. Rather than beginning with the development of large central generation facilities and integrating those resources into the distribution grid, DU planning will begin at the customer level and work outwards. DU planning begins with customer needs, both for the amount of energy and the type of services, and integrates those needs into local and regional systems. In this way, DU planning can provide the most valuable combinations of energy efficiency measures, power quality, back-up power, voltage stability and reliability, while reducing costs and unnecessary investments in new distribution lines.
Developing efficient and valuable DU solutions that meet customer needs will require a variety of planning and implementation skills and, especially significant, coordination between different functional (e.g. generation, distribution) areas. This coordination will take place through DisCos as part of their regulated activities.
Regardless of their overall energy savings, some DSM measures may be effective in reducing the peak electricity demands of customers. In local planning areas where distribution capacity is constrained, DSM, along with local generation options, may delay or eliminate the need for upgrading existing distribution capacity. With effective DU planning, DisCos will ensure that future transmission investments are cost-effective and sized to serve best the needs of customers.
One of the most sensitive issues associated with restructuring is the preservation of the state's natural environment, which is highly valued by Vermonters. Specifically, there is concern that a fully deregulated generation market will provide less costly, but "dirty" electricity, increasing pollution levels in Vermont.
GMP believes that Vermonters will not turn their backs on environmental quality and that they will be willing to pay for "clean" electricity, even if it is slightly more costly than "dirty" electricity. Because Vermont alone cannot restructure the utility industry, GMP believes that all generation in the region should adhere strictly to federal and state environmental statutes. This includes implementation, on an accelerated basis, of New Source Performance Standards (NSPS) for all existing generation that falls under the regulations of the U.S. Clean Air Act.
Consumers will benefit in several ways by movement of new, ultra-clean technologies (such as fuel cells) and renewable generation into the competitive marketplace. To ensure these benefits are realized, DisCos will contribute to the commercialization of these technologies, subject to appropriate PSB oversight. Funds will be collected to support commercialization activities through the DisCo access charge and will be dispersed pursuant to a commercialization plan coordinated with other regional utilities.
As with mandated DSM investment, technology commercialization activities should be accomplished by third parties and generally not by DisCo staff. Where projects that produce electricity are contemplated in commercialization plans, support for such projects would typically be in the form of DisCo funding for the difference between cost and market energy prices, and would be provided through a competitive bidding process.
GMP believes that low-income consumers stand to benefit from competition in the electric utility industry and from the lower energy rates GMP expects competition to bring. Nevertheless, there is a segment of low-income customers who, even with lower electric rates, will remain at risk because of a genuine inability to pay the full cost of the energy services they consume. This may be especially true for customers who face reductions in available money for assistance with their other energy bills.
To ensure that low-income consumers can benefit from competition and are able to pay for electric services, GMP supports the proposition that low-income assistance is necessary in a restructured environment. GMP filed a Lifeline program with the Board in September. Under the proposal, residential customers who earn less than 125% of the poverty level and who are eligible under the Low Income Heating Assistance Program (LIHEAP) would receive winter season discounts ranging from 20% - 40%. The program would be funded by a surcharge levied as part of the DisCo customer access fee charged to residential customers. If GMP's Lifeline program were adopted throughout Vermont, the total funds generated would be approximately $1 million per year, and the access fee surcharge on the approximately 270,000 residential customers in Vermont would be about thirty cents per month.
GMP intends to explore low-income issues further in the context of the restructuring debate.
RetailCos must obtain a certificate of public good (CPG) from the PSB and register with the local DisCos. The CPG will be conditioned upon a showing of credit worthiness, including strict protections due to the fact that the RetailCo will bill and collect the DisCo charges.<4> In order for the DisCos to plan effectively for needed distribution capacity upgrades, these retail suppliers will be required to report the contracts they sign with customers and report customer load information in a timely fashion (consistent with practices to protect confidentiality).
DisCo charges must be separately identified by the RetailCos in their billing statements. In order to preserve the integrity of the ratemaking decisions concerning DisCo charges, RetailCos cannot charge customers more than the approved DisCo charges, but they could charge less. In other words, the approved DisCo rates would represent a ceiling on what the RetailCo could charge for those services.
Practices concerning deposits, refunds and responses to consumer inquiries will be regulated by the State, just as they are for other fuel suppliers today. RetailCos that sell meters to customers will have those meters certified by the State as accurate, much as the State certifies gasoline pumps for accuracy today.
Procedures must be put in place to address allocation of partial payments and provisions for termination of service.
For safety reasons, disconnection for non-payment should be performed by the DisCo. Disconnection should occur for nonpayment of RetailCo-provided energy charges because, unlike telephone service, there is no way to remain connected to the distribution system without continuing to consume energy.
6.6. Protections Against Anti-Competitive Behavior and Undue Market Power
Market power is the ability to influence market prices and subdue rivals. Market power can be used to influence the behavior of customers, of actual and potential rivals and of society in general. Two circumstances that can lead to undue market power are: 1) a monopoly or group of dominant firms in an industry that can control production and market price; and 2) barriers to entry that prevent competitors from offering their products and services in the market.
One concern associated with restructuring is that one or several generation providers will be able to manipulate the market. They could influence market-clearing prices in the spot market pool at certain times of the day or year and influence the price of bilateral contracts. There is concern that the market described in Section 2 will be dominated by a few suppliers in the Northeast, thus reducing or eliminating the cost savings consumers would otherwise enjoy. In New England, two-thirds of the generation capability is currently owned by three utilities. The need for market power protection is underscored by the United Kingdom's experience with competition in the electricity industry.
As a relatively small utility in New England, GMP shares these market power concerns. We do not believe they can be managed effectively using existing U.S. antitrust laws. Antitrust enforcement is lengthy, complex and expensive. These factors jeopardize the viability of a vigorous, competitive generation market.
One mechanism included in the GMP Plan involves a right of first refusal by the affiliated RetailCo to match the highest bid in the generation auction process. Additional protections should be evaluated as well.
More analysis must be performed concerning the causes of undue market power and the most effective remedies. One solution would be to limit the proportion of New England generation capacity that could be owned by a single company. A ceiling, for example, could be established based on current federal antitrust guidelines that provide numerical estimates of market power.<5>
The issue of market power also extends to the transmission market. Access to transmission must be based on objectively determined, ISO-administered rules that do not favor the owners of transmission facilities.
There are two primary transition issues. The first issue addresses temporary measures to assure that every customer continues to receive electric service. The second issue addresses necessary changes to NEPOOL.
The historic regulatory compact has provided customers with assurance of both interconnection and electric energy services, with prescribed rules governing disconnection for non-payment. Under the new structure that GMP envisions, customers can continue to rely on the availability of basic service from their current provider and be able to exercise choice.
The RetailCos that are formed by the separation of functions with a DisCo will be required to provide retail customers located within their former retail service territories with a Basic Service Package. The package would consist of the following components: system access and delivery charges that are a pass-through of the regulated DisCo costs, electric energy at the short-term spot-market price as published by the Power Exchange (or other proxies that are utilized in the interim), associated cost-based TransCo charges, and transaction services at a predetermined fixed cost (to cover customer services and accounting, collections and other administrative and general expenses). In this way, the combined cost of the Basic Service Package will be a combination of regulated prices, predetermined transaction fees and open market energy rates (for large and small customers alike). In addition, the insurance mechanism described in Section 5.4 will provide protection against energy cost increases. To protect against cost fluctuations of the energy price, budget billing would be available to smooth out the payment stream. The competitive market will likely develop a wide variety of other service offerings that incorporate fixed energy pricing for specified time periods (months to years).
The Basic Service Package obligation should be re-evaluated after three years of experience. It is clear that there will be significant competition for customers by the RetailCos, who will be offering a wide range of service options that include energy. After the competitive market fully develops, the need for the Basic Service Package will disappear.
Customers will be allowed to exercise their right to chose another RetailCo and return to their original supplier so long as they provide proper notice and do not do so more than once in a twelve-month period.
In certain other regulated industries where competition has been introduced, customers have chosen their supplier by means of a ballot. Although this approach has merit in many circumstances, GMP believes that it would not be equitable in this case. Balloting favors large suppliers who are able to conduct intensive marketing campaigns just prior to the ballot date. Suppliers other than the GMP affiliated RetailCo will have no obligation to serve all customers, nor will they be required to provide a cost-based Basic Service Package. In these circumstances, a ballot system would be inequitable. Instead, customers should be transferred to the affiliated RetailCo until they choose another supplier.
Today, NEPOOL dispatches the electricity generated by all of the region's utilities based on the marginal costs of those resources. NEPOOL does this to reduce overall regional electric generation costs and to provide a high degree of reliability for the system. NEPOOL also acts as an "account balancer" for the member utilities, distributing the savings each utility realizes by using the centralized dispatch system instead of dispatching each utility's own generating resources. By sharing their responsibilities in this manner, utilities have been able to reduce their operating costs and reduce the amount of generation they must maintain in reserve for reliability and stability purposes. Thus, NEPOOL performs the reliability functions envisioned for the ISO and controls the order in which individual generating units are dispatched to meet overall regional loads.
Four primary transition steps will be required to transform NEPOOL into the ISO and Power Exchange structure incorporated into the GMP Plan.
The first step involves formation of the ISO. NEPOOL's operating arm, known as the New England Power Exchange (NEPEX), already acts much like the ISO. NEPEX coordinates the operational aspects of NEPOOL and maintains reliability of the physical market for the New England control area. NEPEX also monitors and enforces compliance by market members of control area rules. These functions will continue after restructuring. Thus, while governance and control must be reformed to provide for independence, forming an ISO requires little change from current NEPOOL operating practice today.
The second step involves changing the dispatch of power by NEPOOL. Currently, power is dispatched on the basis of incremental generation cost, and not the market prices bid by suppliers. If numerous unregulated generation suppliers are to sell their power through NEPOOL, the dispatch mechanism will have to be changed to accommodate a market based system. In addition, a bid price system must address those generating units that must be run to maintain the integrity of the entire transmission system (so-called "ancillary services"). Furthermore, there will have to be a method of accounting for these suppliers' loads and responsibilities to provide reserve margins and reliability, as required of NEPOOL's current members. An initial approach is to allow new generation suppliers to work in partnership with existing NEPOOL members to do this.
A third step involves metering and power accounting procedures for the use of estimated load profiles that will be associated with metered kilowatthour consumption. This approach allows low-use residential and commercial customers to exercise RetailCo choice without the unacceptable cost of current tele-metering technology. Currently, real-time metering is the basis for constructing the "own-load" dispatch of each NEPOOL member. As NEPOOL members add customer load beyond their current borders and lose load from within, metering and billing procedures will need to be adopted to construct the new own-loads and assign reserve and other responsibilities. For the simulated load shapes, these procedures must address how standard load profiles are constructed, how they vary by geographic area, and how many unique profiles are required.
Lastly, the GMP Plan contemplates the creation of a Power Exchange that will include a short-term spot market for the regional load that is not subject to bilateral contracts. The relationship between the ISO function and the Power Exchange must be carefully designed to both take advantage of current NEPOOL capability and flexibilities that the market demands. The Power Exchange need not be fully operational to begin implementation of this plan.
Before restructuring is implemented, certain requirements must be met, in order to ensure that competition will take place in a fair and equitable manner. These requirements will apply regardless of whether The GMP Plan is adopted as proposed.
Elimination of the current utility retail sales franchises should take place across the region in as consistent a timeframe and as uniform a design as possible. This means implementing a single plan throughout Vermont at the same time. It also means pursuing the same goal throughout the New England region, while recognizing that there are six political and regulatory constituencies involved.
There must be assurance that stranded costs are fully recoverable. Without this assurance, the regulatory bargain that existed when these costs were incurred will be broken, leading to an inequitable and economically inefficient future. Stranded cost recovery also must be even-handed throughout the region.
All customers located in a local utility's service territory must purchase, through the payment of access charges, distribution services from their local DisCo to receive electric power from any source other than on-site generation. Without a strong distribution franchise, large customers could obtain the benefits of power supplied from the electric grid while avoiding payment of their fair share of stranded costs.
There must be adequate protection against the exercise of market power in generation, transmission, and retail sales markets. The concentrated nature of the utility market in New England today requires strong measures be taken to protect against the creation and abuse of market power after restructuring takes place. For generation, there must be assurance that the market price of electricity will reflect a truly competitive price. For transmission, the ISO must develop and enforce objective rules that are not influenced by large generation and transmission owners, to the detriment of smaller companies and their customers. For retail sales, the relationship between local DisCos and any affiliated RetailCos must be sufficiently "arms-length" to permit vigorous retail competition.
Access charge, a charge, set by regulation, to cover the costs of access to the electrical grid, the cost of stranded investments, and the cost of mandated energy-efficiency, renewable resources and social programs.
Basic Service Package, the basic service that any customer would receive. It includes a regulated access charge, a market-based charge for electricity, plus a fixed service charge (for billing and other services).
Cost-of-service regulation, the traditional form of electric utility regulation, under which a utility's prices and its return to investors are based solely on the cost to the utility of providing its services, including a target return on investment.
DisCo, a regulated electric distribution company with a franchise territory and the obligation to connect customers in that territory to the electric grid.
GenCo, an unregulated producer of electricity, which would sell to the RetailCo through individual contracts or through a regional Power Exchange. A GenCo that sells electricity at retail would also be a RetailCo.
Independent System Operator (ISO), an entity that coordinates regional generation and transmission to ensure the safety and reliability of the electric system (in essence performing many of the functions that the NEPOOL does today).
NEPOOL, the organization that currently coordinates flows of power and dispatches generation on the basis of the cost of generation. NEPOOL is also responsible for maintaining system reliability.
The Power Exchange, the marketplace for electricity sales, operating in much the way that the stock exchange does for securities transactions.
Performance-based regulation, an innovative form of regulation that creates incentives for a utility to maintain specified levels of service. Traditional cost-of-service regulation bases a utility's prices and its return to investors solely on the cost to the utility of providing its services.
Regulatory assets, a term that describes assets on a utility's books that the utility would be able to recover from customers under traditional cost-of-service regulation. For example, utilities recover their costs of demand-side management programs over time, and the portion of expenses that have not yet been recovered are considered regulatory assets
RetailCo, an unregulated seller of electricity and other energy services to industrial, commercial and residential customers. It includes power marketers, brokers, aggregators and GenCos selling at retail.
Stranded costs, investments that a utility made prudently in connection with its obligation to serve all customers, but that it would not be able to recover fully in a competitive market. Such investments include generation units, power contracts that price electricity above the market (including contracts with independent power producers), and nuclear plant decommissioning costs.
TransCo, a regulated company that transmits electricity from power plants to local distribution companies. TransCo functions in Vermont are largely provided by VELCO, with support by the 22 electric companies in the state through their distribution systems.
Unbundling, a term that refers to the way pricing will work after the electric industry is restructured. Today, prices for the discrete elements of electrical service are combined (or bundled) into a single kilowatt-hour price. That is, customers pay one price for a variety of services. By unbundling that price, each function--be it actual electricity, transmission, generation, power quality--would be price separately.
VELCO, the Vermont Electric Power Company, a Vermont statewide electric transmission company, owned cooperatively by many of the state's electric utilities.
Vermont Competition Roundtable, parties having an interest in the restructuring of the electric industry, who have been meeting for more than a year to guide the industry restructuring. The parties include representatives of utility regulatory bodies, electric utilities, independent power producers, industrial customers, environmental interests and consumer interests. In mid-1995, the Roundtable issued a set of 14 principles intended to guide electric industry restructuring.
The DisCo could own an insurance policy that could be exercised at the 6 cent market price of power. The policy requires payment to the DisCo for the difference between the market price and the insurance policy trigger price. Local DisCo customers would receive a "rebate" of this amount. In cases where the auctioned plant faces variable costs, the market price is an imperfect proxy.