Issues raised by Stakeholders and Interested Parties
The Virginia, Maryland & Delaware Association of Electric Cooperatives ("VMD Association" representing, in Virginia, A&N Electric Cooperative, BARC Electric Cooperative, Community Electric Cooperative, Craig-Botetourt Electric Cooperative, Mecklenburg Electric Cooperative, Northern Neck Electric Cooperative, Inc., Northern Virginia Electric Cooperative, Powell Valley Electric Cooperative, Prince George Electric Cooperative, Rappahannock Electric Cooperative, Shenandoah Valley Electric Cooperative and Southside Electric Cooperative, Inc.) and Old Dominion Electric Cooperative ("Old Dominion") (collectively, the "Cooperatives") join in submitting this Narrative Outline presenting their comments on the issues presented in Senate Bill 688.
§ 56-576. Short title.
No response required.
§ 56-577. Definitions.
No response requested at this time.
§ 56-578. Applicability; municipalities.
Basic issue: The treatment of municipally-owned and operated electric utilities under a comprehensive restructuring act.
Municipally-owned and operated electric utilities, which currently are not regulated by the State Corporation Commission, should be permitted to continue to operate as they do now within their current municipal boundaries. However, at the discretion of their local governing bodies, customers of municipally-owned or operated electric utilities should be given the opportunity to make a choice of their power supplier in a competitive retail electric market. This should be an election by the local governing body, not a mandate from the state.
A municipal electric utility should be permitted to "opt-in" to competition, but only with reciprocity. If a municipally-owned or operated electric utility opts to market electric generation to retail customers outside of its distribution service territory, reciprocity should be required, meaning that other suppliers of electric energy should be permitted to market electric generation to the municipal's retail customers. This concept also should apply to annexation. If a municipality elects to expand its boundaries by annexation and then attempts to displace the electric generation provider(s) in the annexed area with service from the municipally-owned electric utility, the municipality should be regarded as having embraced competition, and competing retail generation suppliers should be able to offer to supply generation to all of the municipally-owned electric utility's customers
§ 56-579. Schedule for transition to retail competition; Commission authority.
Basic issue: The timeline and structure of transition to retail competition, including timelines, SCC oversight, rate cases, linkages to ISO/RPX formation,
The Cooperatives support concurrent commencement of competition for all customer classes. A significant percentage of the Cooperatives' consumers are residential service customers. The Cooperatives firmly maintain that no class of customers should be left behind when competition commences. Residential customers must have an equal opportunity to make choices about their electric service and to receive the benefits of competition.
In the Cooperative's view, development of a truly independent and efficient Independent System Operator and a properly functioning Regional Power Exchange are essential to the development of competitive retail generation service. However, before regulatory controls on the provision of retail electric service can be reduced or lifted, a number of substantial and significant issues must be addressed. First and foremost among those is market power. Before the development, approval and implementation of either an ISO or an RPX to serve a given region, transmission constraints within that region must be alleviated, or appropriate price controls must remain in place until the constraints are removed.
If there is to be retail competition in Virginia, it should commence regardless of the status of retail competition in other states served by a common ISO. The ISO's primary mission is to give power suppliers comparable, non-discriminatory access to the electric transmission grid while maintaining system reliability. The primary concern about the beginning of retail competition in other jurisdictions relates to fair competition and reciprocity; an incumbent utility in a fully regulated jurisdiction could come in and compete for customers in jurisdictions where retail competition has commenced without facing any competition back in its still-protected service territory. It is impractical to wait for each relevant state to implement retail competition prior to creating the ISO, particularly when the universe of competitive retail sellers would far exceed the number of incumbent utilities from "non-competition" jurisdictions. Delaying the benefits of competition in one jurisdiction because competition has not yet come to another jurisdiction would do more harm than good. To the extent there are concerns about fairness regarding competition with utilities in states without retail competition, Virginia could attempt to limit those utilities' activities in Virginia by adopting a certification process for retail sellers that mandates reciprocity.
The Virginia State Corporation Commission should have authority to adjust the schedule for transition to a competitive retail market. Any legislation adopted should respect the target dates to begin restructuring, but should allow the SCC flexibility to adjust the transition schedule, as there may be unexpected developments that may require additional time to resolve. Also, the schedule for recovery of stranded costs should be subject to adjustment so that stranded cost recovery can be spread over an adequate amount of time so that the rate impacts can be fully considered.
In order to properly unbundle rates, a cost of service study must be performed, which eventually would be part of a filing with the SCC. It also would be appropriate to deal with any necessary rate changes in these filings. The Cooperatives are concerned, however, that without well-defined guidelines for these filings, these cases could become quite protracted and shift the focus away from other equally important restructuring issues. The Cooperatives would welcome the opportunity to work with SCC staff to establish the appropriate structure for the cost of service study, rate changes (if needed) and unbundling of costs into the appropriate components. This process should benefit the Cooperatives in developing their unbundled rate filings and would expedite the SCC staff's review process, since the structure of all the cases would be very similar. The Cooperatives recommend that there be a timeframe established within which the SCC staff's review process should be completed. The Cooperatives also support the notion of phased-in movement toward rate parity at a duly deliberate speed. The SCC has advocated a gradual move away from interclass rate subsidization for some time, and should continue that policy. The Cooperatives believe that a phase-in of rate parity should be considered in order to avoid severe, adverse rate impacts during the transition to the less regulated, more competitive market.
The Commission has nearly completed a rate case for Virginia Power and is well along in a rate case involving Appalachian Power Company/AEP-Virginia. The cooperative business structure, where above-cost revenues collected by the cooperative are returned to the member/consumers, reduces concerns about excessive rates, particularly when the Cooperatives, like everyone else, are scrambling to reduce costs in anticipation of restructuring and retail competition. However, since a modified rate case could provide guidance regarding the unbundling of rates, the Cooperatives are not opposed to a specialized rate case for Virginia's electric cooperatives.
The Cooperatives do not oppose the notion of a rate freeze to allow for the collection of sufficient revenue to defray transitional costs, including transition costs and reasonable estimates of stranded costs. Since costs are generally not regarded as having been "stranded" until load is actually lost due to restructuring, the Cooperatives are reluctant to identify rate freeze proceeds as having been collected in mitigation of stranded costs. Further, since cooperatives return extra revenues to their member consumers, there is less concern about overcollection under a cooperative's rate freeze. A rate freeze should be applied only after a cautious review. In today's stable economic environment, a full price rate freeze may be viewed as giving a competitive advantage to the incumbent utility.
Preliminary wholesale competition is underway. Open access transmission tariffs and the approval of several ISOs currently permits competition at the wholesale level. Wholesale competition has begun but has not yet matured. There is much left to be done. We should focus on ways to improve competition and to assure that reasonably competitive markets develop and thrive.
The prices for all electric services should be unbundled for informational purposes, especially into the component charges for generation functions, transmission functions, and distribution functions. The challenge in unbundling will be the proper allocation of costs among these various functions. FERC already has mandated the unbundling of wholesale generation costs, transmission costs and the costs of ancillary services. In order to evaluate fully and fairly the costs involved in a competitive retail electric marketplace, it will be necessary to unbundle retail service costs among retail generation costs, retail transmission/distribution costs and retail service costs.
The Cooperatives support the use of pilot programs to gain experience in how competition in retail sales of electricity may develop. Pilot programs may provide useful input in structuring an orderly transition to retail competition in the Commonwealth. However, it is important to understand that a pilot is designed to test the technical aspects of a model, not to demonstrate the level of savings, which may occur from retail access. Any savings generated in a pilot program where the number of participants is limited and the supply is not would yield a distorted pricing picture. Pilot programs must be carefully crafted to allow for the collection of useful information while not creating a laboratory that can be manipulated to magnify (or conceal) problems in retail competition.
§ 56-580. Nondiscriminatory access to transmission and distribution systems.
Basic Issue: Access by electricity suppliers to transmission and distribution systems currently owned and operated by incumbent electric utilities.
The distribution of electricity in a competitive market should continue to be conducted much as it is now, with the incumbent electric utilities retaining the obligation to provide distribution service in certificated distribution service territories. For distribution cooperatives and investor-owned utilities, oversight of distribution operations and rates will continue to be within the SCC's jurisdiction. The SCC should be responsible for assuring open, non-discriminatory access to distribution systems and appropriate distribution system reliability. ISOs will be reviewed, approved and regulated by FERC. The SCC (and other involved public utility commissions) should have a voice in governance of the ISO through a seat on the board of directors or a suitably empowered advisory board. Also, the SCC will have a significant role in the initial approval of any ISO that is operating facilities in Virginia.
Transmission system constraints serve to enhance market power in a given control area. If any market participant can wield unreasonable market power, the market will likely be distorted and not mature into a truly competitive market. A constrained transmission system can enhance a market participant's market power because generators outside the constrained control area may not be able to sell into that area and generators within the constrained area will have what is essentially a captive, monopoly market. Before the development, approval and implementation of either an ISO or an RPX to serve a given region, transmission constraints within that region must be alleviated, or appropriate price controls must remain in place until the constraints are removed.
If the electric industry is to be restructured, the restructuring must be such that no market participant is able to exert significant market power influences on the availability or pricing of electricity. In light of the traditional industry structure and organization and the physical characteristics of electricity, the restructuring process must include measures to effectively alleviate factors that could engender anti-competitive practices. Large, vertically integrated utilities generally own and operate the transmission system and the majority of the generation resources within their control area. In addition, transmission constraints and voltage support requirements often restrict power transfer capability into and within a given control area. The combination of concentrated ownership and control of generation and transmission facilities within a control area and limited import capability can provide a vertically integrated utility with significant market power.
In particular, transmission limitations can eliminate much of the generation competition from meaningful participation in a given market. When a limited interface has low or zero Available Transmission Capacity ("ATC"), any generation owner that must transmit through that interface may be unable to make deals over that interface. The absence of adequate import capability will effectively bar generation suppliers outside of a given control area from competing within that control area. Firm and non-firm capacity purchases, as well as the non-firm economy markets, are adversely affected by transmission limitations. The Structure and Transition Task Force must consider existing transmission constraints in Virginia in determining what manner of restructuring would best serve Virginia.
When the import capacity of the transmission system in a given control area is constrained, significant market power influences may be exerted. Further, there is a potential for market distortion if costs, particularly variable costs, are not kept in check. In the Virginia Power system, major improvements are necessary to increase import capability and dilute Virginia Power's market power. Some argue that new generation sufficient to eliminate anticompetitive effects would be constructed within constrained control areas. The Cooperatives urge the Task Force to remember that the electricity business requires capitol intensive, long-term investments. It takes several years and a lot of money to build new generation. The Cooperatives believe that current transmission constraints on the Virginia Power system must be addressed in the process of developing a restructuring plan for Virginia.
The Cooperatives believe that to the extent the import capacity of the transmission system in a given control area is constrained, there is a potential for market distortion if costs, particularly variable costs, are not kept in check. Therefore, the rates for power from generation facilities within a constrained control area should be limited to cost of service until such time as the constraint is relieved or until sufficient new generation capacity has been constructed within the constrained area by several independent generators.
§ 56-581. Independent system operator.
Basic issue: The role of regional independent system operators (ISOs) in furnishing generation dispatch coordination.
Prior to addressing the specifics of ISO governance and operation, the Cooperatives recommend that the Task Force consider what an ISO should do and what an ISO will not do. A substantial amount of money will be involved in creating and operating an ISO, money that will be recovered from customers. The costs and benefits of creating an ISO must be considered before an ISO is put in place.
The two primary purposes of an ISO are (i) to provide non-discriminatory access to the electric transmission grid and (ii) to maintain system reliability. The end result of restructuring and creating an ISO should be that the price of electricity to the end consumer will be lower, due to competition, without adverse effect on the reliability of the transmission system.
To achieve savings for the ultimate consumer, the ISO must provide access to lower cost generation (or, in the long run, lead to the construction of new, low-cost generation) that will more than offset the cost of developing and operating the ISO (and the RPX). It does not make economic sense to reduce the regulation of electric utilities, restructure the electric industry and allow retail competition unless there is a significant degree of confidence that there will be savings for the ultimate consumer.
Creating an ISO will not change the physical layout of the transmission system. The transmission system and generation facilities will be the same the day before and the day after the ISO commences operation. One thing that will change is the basis for choices made in operating of the system. Presently, individual control areas are under economic dispatch, i.e., the most cost-effective unit is run first. In the restructured environment, this will not necessarily be the case. If properly and independently operated, the ISO will make decisions to run units without regard to economics, placing a greater priority on keeping the system functioning. However, the ISO will not make the system larger, better or stronger. If there was insufficient transmission capability to import power before the ISO began operating, there will still be insufficient capability under the ISO, and lower cost generation that could offer savings to the ultimate consumer will still be unreachable.
This Task Force and the General Assembly should keep an eye on the ultimate goal of restructuring, which is lowering the cost of power for the ultimate consumer. To this end, a great deal of caution must be exercised in the course of developing an ISO and RPX. It may be wise to create the ISO and put it into operation before allowing retail competition to commence. This should encourage improvement of the transmission system and the development of lower cost generation while inhibiting incumbent utilities from reaping windfall profits by sending low-cost generation to high-price areas and offering only higher priced generation in return.
If a given ISO is to be an effective mechanism that will be fair to all stakeholders and beneficial to all of Virginia's ratepayers, it is essential that all stakeholders be fairly represented, not only in the formation process, but also in the ultimate structure and governance of the ISO. In particular, Virginia's cooperatives, as transmission dependent utilities, must have both influence and authority in the formation and governance of any ISO that pertains to them. The ISO should have an independent board of directors, the majority of whom have no interest in the entities that operate under the direction of the ISO. All stakeholders should have some representation on the board of directors. The State Corporation Commission and other involved public utility commissions should also play a substantive role in development of the ISO and should be represented either on the board of directors or another suitably empowered advisory committee.
As discussed earlier herein, the primary function of the ISO will be to assure comparable, non-discriminatory access to the interstate electric transmission grid. The ISO will likely comprise territory in several states and will be subject to FERC's jurisdiction. As such, it will be difficult to impose state-specific public interest standards on the operation of the ISO. However, Virginia should be able to influence the development and operation of an ISO affecting its citizens through participation on the board of directors or another advisory board, by conditions placed on the state's initial approval of the ISO and through its continuing role in approving the siting of facilities within the state.
After an ISO has been formed and put into operation, Virginia will have limited oversight authority. Oversight authority will have been ceded to FERC. However, the state will still be able to exert some influence if it continues to control approval of the siting of facilities within the state.
The ISO will have primary responsibility with regard to coordinating with load serving entities, voltage stability, generation reserves and overall transmission upgrades and reliability. The ISO's role in generation upgrades and reliability should be somewhat more circumscribed. The ISO should control the transmission system and have authority to mandate actions by participants, particularly regarding system security and reliability. The ISO should also have an advisory role in decisions regarding generation facility upgrades and responsibilities.
Generation units may be identified as must-run units for a variety of reasons. A generation unit may be identified as a must-run unit because of its character (e.g., nuclear facilities), because of system needs (e.g., units that must run to provide reactive power support or because of system constraints) or because of a contractual obligation (e.g., cogeneration facilities with a steam host). Some generation units will be identified as must-run units at all times while others will be identified and designated as must-run units by the system operator only when conditions on the transmission system require that they run. Units designated as must-run units by the system operator must be obligated to run at the direction of the system operator.
The Cooperatives believe that a properly structured, broad, mandatory ISO is necessary for the development of a legitimate competitive market for electricity and that a larger, regional ISO is better because it will broaden the competitive generation market and include more participants. However, the discussion should not focus on the size of a particular ISO or a minimum size requirement. The key is to assure that a hodgepodge of small, inefficient ISOs does not develop. There should be incentives to give transmission-owning entities the appropriate motivation to join an appropriately structured ISO.
The power of eminent domain and related rights of condemnation should need to be exercised only in relation to transmission and distribution line routing and construction. The siting of generation facilities and the arrangements to secure the property needed for such a facility should be largely a private matter. Therefore, reserving the power of eminent domain and rights of condemnation to the entities responsible for transmission and distribution planning should be sufficient. If an ISO is responsible for system planning, the transmission owner can exercise the power of eminent domain at the direction of the ISO. This would require a clear statement in the ISO agreements of the ISO's authority to mandate system additions and improvements.
Dispatch of all units, including must-run units, should be in the hands of an ISO. The ISO should identify must-run units on an hour-by-hour basis when conducting its system analysis for the next day and construct its transmission plan accordingly. The Cooperatives have previously stated their preference for separation between the ISO and the RPX so that the ISO will be operated without regard to economic factors. The ISO should not factor economics into its generation dispatch equation. A must-run unit presumably will be dispatched without regard to its economics, with its bid price "zeroed-out" of the price calculations.
§ 56-582. Regional power exchange.
Basic issue: The role of regional power exchanges in providing electricity pricing mechanisms.
It will be difficult to impose state-specific public interest standards on the operation of an RPX. The RPX will serve a market function, creating a competitive marketplace where buyers and sellers of power can complete trades through an electronic auction that will establish a market-clearing price for each hour of the day. The RPX will coordinate with, and may be operated by, the ISO serving the region, in order to arrange delivery of the power purchased. The RPX will include a variety of participants that will be buying and selling generation, at wholesale, for delivery within several states in the region served by the ISO. Being wholesale sales, FERC authorization must be obtained prior to making sales through the RPX at market-based rates. FERC will have jurisdiction over the sales made through the RPX. It would be difficult to conform the RPX to standards imposed by each state it serves.
Virginia may be able to influence the development and operation of an RPX affecting its citizens through participation in the relevant FERC proceeding. The Commonwealth could argue for continuing cost-of-service pricing for several years, until the kinks are worked out. Virginia also could seek to place a representative on the board of directors of the RPX or on an advisory board. Virginia may also be able to influence the RPX through whatever authority it preserves over the approval and siting of generation facilities.
In the Cooperatives' view, bilateral contracts for the sale of generated electricity, not conducted through the RPX, are acceptable. As explained below, given their tax structure, bilateral contracts may be a necessity for many cooperatives unless the federal tax code is modified. Accordingly, the Cooperatives support allowing the use of bilateral contracts, outside of the RPX, for the sale of generated electricity.
The Cooperatives believe that a properly structured, mandatory RPX is necessary for the development of a legitimate, competitive market for generated electricity, but that not all sales need be made through the RPX. As stated above, bilateral contracts are appropriate and, to many cooperatives, necessary. The RPX should be mandatory in the sense that all uncommitted capacity should be sold through the RPX.
An area of significant concern to some cooperatives is the impact that sales made through an RPX may have on a cooperative's tax-exempt status. Old Dominion is the wholesale power supplier to its member distribution cooperatives, including nine in mainland Virginia. If the wholesale sale of power between Old Dominion and its member cooperatives was conducted through an RPX (with payments for generation funneled through the RPX), under the current tax code those payments would be regarded as non-member revenue. This would likely put Old Dominion's tax-exempt status in jeopardy. If nonmember revenue exceeds 15% of a cooperative's total revenue, the cooperative would lose its tax-exempt status and its cost of providing power to its members would increase substantially. If Old Dominion's generation was sold through an RPX, its non-member revenue immediately would surpass the 15% threshold. Therefore, the Cooperatives support the use of bilateral contracts, outside of the RPX, for the sale of generated electricity.
As stated earlier herein, the Cooperatives believe that if system constraints are affecting dispatch, generation in the constrained control area should be kept under cost-of-service pricing until the constraint is relieved. If, after system constraints have been addressed, an RPX is in operation, generating units identified as must-run units for transmission purposes should be excluded from price calculations so as not to skew the price. Such must-run units should be subject to continued cost-of-service pricing or permitted to charge the market-clearing price as calculated exclusive of any bid price for the must-run generation units. The price of generation from "contractual" must-run units should be set by the contract (which might be a subject of the stranded cost determination) or by the market.
§ 56-583. Transmission and distribution of electric energy.
Basic issue: The regulatory and structural framework for electricity's transmission and distribution.
For transmission and distribution, one goal of restructuring has been to provide comparable and non-discriminatory access to the facilities necessary to deliver the commodity, electricity, from the seller to the buyer. Ideally, the cost of and ability to access the delivery system would be neutralized. Accordingly, to the greatest extent possible, incumbent utilities and new market entrants should be able to arrange delivery under the same terms. Transmission and distribution rights should be judged by a public interest standard, with fixed rights favoring the consumer, not the owner of the system.
As stated earlier herein, the power of eminent domain should be exercised almost exclusively in relation to transmission and distribution right-of-ways. Therefore, that power should be exercised only by transmission and distribution entities that continue to be subject to state or federal regulation. The SCC should continue to oversee the use of the power of eminent domain by transmission and distribution entities in Virginia.
The siting of merchant plants and any other new generation should remain subject to approval by the state. In the interest of the health and welfare of its citizens, each state should preserve its authority over the siting of all new generation within its borders. The standards for evaluation of proposed facilities may change, with a greater emphasis on the benefits to the regional electric system rather than simply the usefulness to one state's citizens, but the state should reserve its authority over the siting of new generating facilities.
In Virginia, recent legislation has already changed the standard to be applied in evaluating proposals for new generating facilities. Under the 1998 amendments to §56-265.2 of the Code of Virginia, an applicant no longer needs to establish that the service rendered by the current certificate holder is inadequate to the requirements of the public necessity and convenience in order to obtain approval of a proposal to construct and operate electrical generating facilities in the certificated service territory of another entity. The Commission must find that such generating facilities (i) will have no material adverse effect on the rates paid by customers of any regulated public utility in the Commonwealth; (ii) will have no material adverse effect on the reliability of electric service provided by any such public utility; and (iii) are not otherwise contrary to the public interest. The Commission also must give specific consideration to the environmental effects of such facilities and may establish conditions to minimize adverse environmental impacts. The legislature should preserve and enhance the SCC's role in reviewing applications to construct and operate new electrical generating facilities in Virginia.
The distribution of electricity in a competitive market should continue to be conducted much as it is now, with the incumbent local utilities retaining the obligation to provide distribution service in certificated distribution service territories. Any other arrangement would encourage an inefficient and unnecessary duplication of facilities, and might have a negative impact on service quality. Oversight of operations and rates for distribution cooperatives and investor-owned utilities should continue to be within the SCC's jurisdiction.
§ 56-584. Regulation of rates subject to the Commission's jurisdiction.
Basic issue: Transitional and ultimate rate regulation for bundled and unbundled electric service.
First and foremost, the restructuring effort and any restructuring legislation must focus on introducing competition in the generation function. The creation of a broad-based, functioning and truly competitive market for retail generation service is the centerpiece of the restructuring process. Absent an operating competitive retail market, discussion of other competitive services is pointless. Establishing an effective and efficient retail generation market is the linchpin for the development of other competitive electricity services.
Several parties have suggested that there be competition and customer choice in billing and metering. However, the Cooperatives maintain that legislating competition in metering and billing is not an essential component of restructuring. The Cooperatives continue to believe that billing should be provided by the entity providing distribution service.
Another electricity-related services that may see greater competition following restructuring is load management services. A fledgling competitive market for load management services has already emerged. Numerous entities are offering customers energy audit and electricity consumption management services, presumably in preparation to offer retail generation supply when retail competition becomes a reality.
§ 56-585. Licensure of suppliers of retail electric energy; license suspension or revocation; penalties.
Basic issue: Licensing, financial responsibility and customer service requirements imposed on all suppliers of electricity within the Commonwealth.
The SCC should be given authority to create a certification program for power suppliers in order to evaluate and monitor their financial viability and their ability to perform. This will help assure that power is available to consumers when they need it (i.e., reliability) and that funds are available to cover liabilities and penalties for any failures to perform. In order to be certified, a power supplier should be required to show, at a minimum, that (i) it has access to actual generating facilities to support its sales; (ii) it has adequate reserves to meet regional reliability standards; (iii) it has the means to deliver the power it sells; and (iv) it has the financial integrity to meet its objectives.
§ 56-586. Suppliers of last resort [and default suppliers].
Basic issue: Determining the generation suppliers of electricity customers who (i) are unable to obtain generation supply services, or (ii) do not affirmatively choose generation suppliers.
The "supplier of last resort" is the supplier for customers otherwise unable to secure service because of payment problems and the supplier for customers whose power supplier has failed to deliver as scheduled. The Cooperatives believe that the distribution service provider should serve as the supplier of last resort. For serving as the supplier for customers otherwise unable to secure service because of payment problems, the supplier of last resort should receive reimbursement through charges collected from all retail power suppliers.
In a competitive retail electric market, customers will have the opportunity to choose their retail electric supplier. Regardless of this opportunity, some customers will simply refuse to make a choice. Default service will be available to those customers that do not make a choice regarding their retail electric supplier. The distribution service provider also should serve as the default provider. However, no customer should be required to choose a different or "alternative " supplier.
Any restructuring plan adopted for Virginia must recognize that many customers will make a choice to remain with their incumbent electric provider. Unlike their investor-owned brethren, most of the Cooperatives will not create elaborate marketing structures and strategies to sign-up their existing customers under the umbrella of a newly organized and creatively named retail sales division. The Cooperatives want their member/consumers to continue to buy power from the cooperative and hope (as well as expect) that most of their member/consumers will want the same. The Cooperatives' member/consumers should not be classified as default customers simply because they did not choose an "alternative electric supplier." A cooperative's consumers own the cooperative, and they should not be forced to take actions that are adverse to that ownership interest.
A choice to remain with the incumbent electric utility is equally valid as a choice to switch to an alternative electric supplier. Loyal customers choosing to remain with their incumbent supplier should be distinguished from customers not making a choice. Only those customers that have not made any choice regarding their retail electric supplier should be classified as receiving default service from the default provider.
Through a properly constructed certification program, the SCC should have authority to investigate whether a power supplier has sufficient access to adequate power supplies and the financial stability to conduct its business in Virginia. If the power supplier has failed to deliver generation as scheduled and the supplier of last resort is called upon to serve as the back-up supplier, the supplier of last resort should have the authority to charge a premium to the power supplier or, if necessary, to the customer. Customers should be liable for the costs of emergency replacement power only as a last resort. Also, in the event power is unavailable and the system operator calls for load reduction, the customer whose supplier has failed should be subject to disconnection before other customers (presuming individual disconnection becomes technically feasible).
§ 56-587. Voluntary aggregation permitted.
Basic Issue: The framework within which individual electricity customers may aggregate demand in negotiating for generation supply.
The Cooperatives strongly support the right of customers to join together and aggregate demand in order to negotiate more favorable terms for generation supply. The Cooperatives would even go so far as to recommend that people interested in aggregating demand consider forming a cooperative to serve that purpose. Owned by those we serve, the Cooperatives have been and will continue to be at the forefront of bringing consumers together to obtain better service and better pricing for their electrical needs.
§ 56-588. Metering, billing and other related distribution services.
Basic Issue: How billing, metering and related services will be handled and regulated.
As stated above, regarding billing and metering functions, the Cooperatives believe that billing and metering should be provided by the entity providing distribution service.
Unlike generation, transmission and distribution will continue to be regulated by federal and state authorities. Even in a restructured generation market, exclusive, certificated service territories will be maintained for distribution service. The distribution service provider will have an obligation to provide distribution service to everyone in its certificated territory, and may be obligated to assure that generation is available. The Cooperatives believe that control of metering is an essential aspect of operating a distribution system, and that along with the duty to serve should come the right to bill for services it is or may be obligated to supply.
Competition in billing and metering may lead to an inefficient duplication of efforts and would create an unnecessary gap between the distributor and the customer, which could create confusion and have a negative impact on service quality. The restructuring plan should not mandate competition or customer choice in billing services (an area not previously subject to specific regulation) nor create competition in metering.
The distribution service provider also should be responsible for maintenance of the distribution system. The distribution provider may elect to contract certain services out on a competitive basis, but that should be the choice of that distribution company, not a government mandate.
The Cooperatives believe that in order properly to operate the distribution system and to plan and budget for the maintenance and improvement of the distribution system, the distribution company must know how the system is operating, where the load centers are, where load growth is taking place and what actions need to be taken to keep the system functioning reliably. This information is most easily and economically obtained by requiring the distribution company to continue to provide metering and maintenance on the system. The Cooperatives believe that opening metering and billing to competition will increase costs while, over time, decreasing the reliability of the distribution system.
§ 56-589. Consumer protections and customer services; penalties.
Basic issue: Maintenance of customer service functions during and after transition to retail competition, plus consumer information and disclosures during transition.
[No response requested at this time; issue is before the Consumer and Environmental Education and Protection Task Force].
§ 56-590. Public purpose programs.
Basic issue: The establishment or continuation of public benefit programs, including universal service, energy efficiency and conservation, etc.
[No response requested at this time; issue is before the Consumer and Environmental Education and Protection Task Force].
§ 56-591. Transition costs and benefits.
Basic issue: Allowance for and calculation of stranded costs and benefits-an issue currently before the task force assigned this topic.
No response requested at this time since this issue is currently pending before the Stranded Costs Task Force.
§ 56-592. Nonbypassable wires charges.
Basic issue: The extent to which and the methods by which retail customers could be assessed pro rata surcharges for stranded cost recovery, the cost of establishing ISOs and RPXs, the cost of public purpose programs, etc.
This basic issue comprises a number of sub-issues because of the variety of costs it encompasses. Generally, stranded costs are utility's prudently-incurred, past costs that cannot be recovered because of the switch to a competitive market, while the cost of establishing ISOs and RPXs are transition costs and the costs of operating ISOs and RPXs and supporting public purpose programs (e.g., demand-side management, environmental protection programs, assistance programs) are ongoing costs. The consistent theme running through these issues is that all customers should share these costs. The most efficient and consistent method to collect these various costs is through a wires charge levied on all consumers by the distribution company, based on usage (per kWh). The charges for each of these costs should be listed and treated separately. Assessing nonbypassable wires charges based on usage would provide an additional reason for having the distribution company handle metering and billing.
§ 56-593. Divestiture not required; functional separation [and other corporate relationships].
Basic issue: Treatment of incumbent utilities' current vertically integrated structure.
The Cooperatives do not favor mandatory divestiture. Functional separation with appropriate codes of conduct and adequate enforcement mechanisms should be sufficient to address concerns about fair competition in the restructured market. In fact, the Cooperatives oppose permissive authorization of a proposed divestiture in a constrained market. Such asset sales should be permitted only if the sale price is at or below book value. The uncontrolled divestiture of generation assets for quick profits in a constrained market will likely lead to higher prices for consumers. The Cooperatives recommend that where the market is constrained, in addition to limiting the price of generation to cost of service rates until market constraints are relieved, every proposed divestiture should be closely scrutinized.
Much as there is a need for functional separation at the wholesale level, which the ISO and RPX structure is expected to accomplish, there is a need for functional separation between generation and distribution at the retail level. As stated previously herein, the Cooperatives support functional separation of operations over either mandatory divestiture or physical separation of operating units. For most cooperatives, functional separation of wholesale generation and distribution is standard operating procedure - either because they do not own generation or because what generation they own is owned through a power supply cooperative such as Old Dominion. The Cooperatives also support functional separation of retail generation and distribution. For the Cooperatives, any other arrangement likely would be prohibitively expensive and may have adverse impacts on their business and tax structure.
An issue raised in most restructuring discussions relates to the conduct of relationships between suppliers or distributors and their affiliates and whether an code of affiliate conduct is needed. The Cooperatives do not oppose codes of affiliate conduct. In serving their member/owners, the Cooperatives have and will continue to follow a code of ethical conduct. The Cooperatives need no regulatory mandate to guide their good business conduct. Good customer relations and good service are simply good business practices. However, to the extent there are to be codes of conduct, the Cooperatives believe that the regulation of affiliate conduct should be narrowly tailored so as not to impede competition. The legislature should not expand the state's regulatory authority into previously unregulated businesses because the business happens to be undertaken by a formerly regulated utility. However, certain aspects of the relationship between suppliers or distributors and their affiliates may be appropriate for regulation, in the public interest.
While the Cooperatives do not object to a code of conduct, they also do not believe that an expansive or strict code of affiliate conduct is necessary for cooperatives. The Cooperatives continue to be not-for-profit, member-owned, federal tax-exempt organizations. The activities of the Cooperatives, particularly their financial activities, are scrutinized by the State Corporation Commission, the Internal Revenue Service, the Rural Utilities Service, other lenders, rating agencies and the member/consumers elected to the cooperative's board of directors. With this level of scrutiny, and with a business motivation to best serve the member/consumers without focusing on profitability, there is no need for an elaborate or restrictive code of conduct for cooperatives.
The Cooperatives do not advocate a general moratorium on mergers and acquisitions at this time. As with the treatment of divestiture of generation in a constrained market, the Cooperatives believe that during this period of restructuring and other upheaval, each proposed utility merger or utility acquisition of another utility must be closely scrutinized, applying a full array of market power and other competitive impact analyses.
§ 56-594. Legislative transition task force established.
Basic issue: The role of the General Assembly during phase-in to retail competition.
The General Assembly should continue to vigilantly monitor the progress of the transition to retail competition in Virginia. The General Assembly should enact legislation that establishes the parameters of what will be permissible regarding the important issues in restructuring, then direct the SCC to manage the restructuring process with sufficient flexibility to address unique problems and novel situations that are bound to arise. The General Assembly should authorize the SJR 91 Subcommittee to continue its work and meet periodically to receive regular reports from the SCC on its progress in accomplishing the General Assembly's directives.
Basic issue: Striking a competitive balance between incumbent utilities and new market entrants.
The market power associated with existing generation largely will be attributable to transmission system constraints. As discussed in detail earlier herein, transmission constraints should not be used to create or preserve a market advantage for generation located within the constrained area. It will undoubtedly take some time to relieve constraints on the transmission system, which can be accomplished by transmission system improvements or new generation within the constrained area. In any event, until known transmission constraints are addressed, generation within the constrained area should be sold only under regulated, cost-of-service based rates.
The Cooperatives agree that there are market power impacts associated with the control of existing generation sites relative to their candidacy for the construction of new, incremental generation, but are unaware of any cogent method by which to determine, evaluate, quantify or assess those impacts. While there may be some clear economies associated with adding additional generation at an established site, it is difficult to discern how the overall market advantages or impacts of such sites could be measured. If another entity sought to use space at an existing site, the owner would have to be compensated for the considerable cost of developing and permitting the site and related facilities. The state could develop a licensing program for plant sites, whereby unused space could be licensed to another developer proposing to construct additional generation, or the power of eminent domain could be expanded to allow a new developer to secure an available site through condemnation. In either case, the compensation to be paid to the site owner would be difficult to determine.
There are competitive advantages associated with the ownership of SO2 allowances and the ability to generate NOx offsets necessary to build generation in non-attainment areas. The question is whether and how such advantages can be addressed. It appears that, at this point in time, SO2 allowances can be readily obtained, while arranging NOx offsets is a more difficult task.
The Clean Air Act of 1990 established the Acid Rain Program whereby SO2 allowances were distributed to utilities. Under the Acid Rain Program electric power plants either had to reduce their emissions to a prescribed level or purchase sufficient SO2 allowances to cover the volume of their emissions. In Phase I of the Acid Rain Program, many units "overcomplied," creating an ample supply of SO2 allowances for sale. With an ample supply readily available, the "market price" for SO2 allowances has been very reasonable. Thus, a new generating unit can be built with state-of-the-art pollution control equipment or after purchasing sufficient SO2 allowances on the open market.
NOx offsets are not so readily available. NOx emissions are a result of any combustion process and cannot be reduced with "end-of-the-pipe" technology. For many years now, the U.S. Environmental Protection Agency has been setting stringent NOx emission standards for the various industries that produce NOx, and an offset can be produced only by a reduction that goes above and beyond the standard. Many facilities already are using state-of-the-art combustion technologies, so there are very few NOx offsets available. The cost of arranging NOx offsets (e.g., purchasing and closing a plant emitting NOx, putting low NOx burners in an existing facility) can be extremely high, and will likely increase over time.
Also, since the NOx offset program only comes into play in non-attainment areas, there are economic disincentives to locating in these areas. The NOx offset requirement in a non-attainment area may push the costs of developing a project to unacceptable levels. One solution tried in other states has been to have the state create a NOx offset "bank" that would be made available to new developers in nonattainment areas. The offsets in the bank are drawn from facilities that are no longer in operation for any number of reasons. Both Maryland and Delaware have established state-operated programs to deal with NOx offsets.
At present, SO2 allowances can be easily purchased, offsetting any competitive advantages associated with holding SO2 allowances created under the Acid Rain Program. However, the legislature may have to develop a plan to address the competitive advantage associated with the ability to create NOx offsets.
The distribution service provider should serve as the default supplier. The Cooperatives do not believe that it would be in the public interest or in the best interest of consumers to simply replace the incumbent utility as default supplier. If the incumbent provider is able and willing to continue to meet the terms and conditions of service, there is no need for an alternative default supplier. There is no reason to institute a change just for the sake of change.
Another issue is the definition of default service. In a competitive retail electric market, customers will have the ability to choose their retail electric supplier. The choice could be an alternative electric supplier or the incumbent electric utility. The customers classified as being served by the default supplier should be only those customers that have not made a choice regarding their retail electric supplier. If a customer elects to remain with the incumbent electric utility, that choice should be respected. There should be no involuntary changing of generation suppliers ("slamming"), either by the state or unscrupulous power suppliers.
If there is to be competition for default service, the Cooperatives believe that such competition should be limited. The Cooperatives recommend that there be competition for the role of default supplier only if the incumbent default supplier fails to comply with the rates, terms and conditions established for service in its service territory or if it is established, after notice and hearing, that the service rendered by the default supplier is inadequate to the requirements of the public necessity and convenience.
The Cooperatives believe that there should be significant deference regarding contracts and that the sanctity of contracts should be preserved to the greatest extent possible. Most customers, particularly sophisticated industrial and commercial customers, presumably made reasonable judgments in executing their power supply contracts. The state should not presume to substitute its judgment for that of an individual citizen or business regarding an agreement that was struck for electric service. In addition, Virginia has encouraged pre-competition deals, recently enacting legislation allowing utilities to offer special incentive rates to attract business to or keep business in Virginia. The state should not now take action that would contradict that policy. Existing long-term retail electric contracts should be honored through the commencement of retail competition.