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Transmission access rights and tariffs
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Electric Power Systems Research 43 (1997) 197-206
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Transmission access rights and tariffs Lester H. Fink a.,, Marija D. Ilic b, Francisco D. Galiana c KEMA Consulting (retired), 250 Pantops Mountain Road, Box 4, Charlottesville VA 22911, USA b Massachusetts Institute of Technology, Cambridge, MA 02139, USA c McGill University, Montreal, Quebec, Canada Received 4 March 1997
Abstract Much of the current debate in the US surrounding the deregulation of electric power supply and the associated restructuring of that heretofore vertically integrated industry has been concerned with measures to nullify or eradicate any market power based on control of access to transmission by the traditional utilities. The debate has had to do with various degrees of 'unbundling' of control of the two assets (generation and transmission) in order to ensure that all power suppliers - - various types of independent power producers and power marketers - - have access to transmission that is as unfettered as that of the owners. The argument of this paper is that any assigning of transmission access 'rights' to power suppliers of any ilk is de facto a 'rebundling' of what it has been desired to 'unbundle.' In addition, assigning transmission access rights to suppliers is bound to inflate the demand for transmission capacity, whether in the short or the long run, because multiple suppliers will seek to secure access rights for prospective transactions for which they are competing. An alternative approach is suggested, based on the facls that existing transmission has been provided to ensure adequate and reliable supply to existing loads, that the relation of transmission capacity and loads is stable (whereas the relation of supply and loads, and hence of supply and transmission will be increasingly volatile), and that transmission constraints have conventionally been defined and monitored in terms of imports (to loads) across critical interfaces (cut sets). From this perspective, assigning of transmission access rights to loads (as their proportionate share of imports across critical interfaces), and charging for such access in the traditional mode of regulated return-on-investment: tariffs would avoid almost all the difficulties hobbling the current debate. © 1997 Elsevier Science S.A.
Keywords: Power system transmission access; Power system restructuring; Power system transmission tariffs
1. Introduction In the course o f its o n g o i n g fostering o f the restructuring o f the nation's electric energy industry, the Federal Energy Regulatory Commission ( F E R C ) has released, in parallel, an Order and a further Notice o f P r o p o s e d Rulemaking ( N O P R ) . Order 888 [1], which m a n d a t e s opening o f utility transmission lines to competitors, includes a pro f o r m a tariff providing terms and conditions. The N O P R [2] proposes to replace that pro f o r m a transmission tariff with a new capacity reservation tariff (CRT). Distributed t h r o u g h o u t the C R T N O P R are statements setting forth n u m e r o u s ad-
* Corresponding author. Tel.: + 1 804 9809344; fax: + 1 804 2967450; e-mail: [email protected] 0378-7796/97/$17.00 ~' 1997 Elsevier Science S.A. All rights reserved. PIIS0378-7796(97)01181-4
vantages o f the p r o p o s e d C R T . We question certain assumptions that seem implicitly to underlie the C R T , and fear consequently that some o f the alleged advantages are illusory. We believe further that correction o f the implicit assumptions can lead to an alternative p a r a d i g m that would actually provide :many of the advantages claimed for the C R T . In an earlier article [3], a case was put forth for recognizing the obligations o f loads relative to requirements for ancillary services. In this article., a case is put forth for recognizing the rights o f loads relative to equal presence at the table where the market functions. Based on our c o m m e n t s submitted to F E R C in response to the C R T N O P R , we identify assumptions we believe to be underlying that N O P R , :motivate and outline our alternative paradigm, and indicate what we see to be its n u m e r o u s advantages.
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2. Background
The ostensible objective of the flourishing reconceptualization of the electric energy industry (the industry) that is currently in process is the reduction of energy costs to end users by replacing a regulated monopoly industry by a competitive free market industry. A prominent feature of the resulting transformation of the industry is the emergence of a variety of new power producing and power marketing entities in competition with the traditional utilities. A major focus of the activities of the Federal Energy Regulatory Commission (FERC) has been to preclude the entrenched utilities from using their market power and control of the existing transmission networks to the disadvantage of the new entities. This latter aim is being fostered by putting in place various requirements intended to insure open access to bulk power transmission facilities on the part of the new entities. These objectives necessarily are to be achieved without endangering the traditional proven reliability of the industry in the US. The essence of the capacity reservation tariff concept put forth in the C R T N O P R is stated as follows: " U n d e r the CRT, which would replace existing transmission tariffs, all firm transmission users, including the transmission owner on behalf of its wholesale requirements and bundled retail customers, would nominate and reserve transmission capacity; they would nominate and reserve firm rights to receive specific amounts of power at specific grid PORs [points of receipt] and to deliver specific amounts of power at specific grid PODs [points of delivery]." [[2], p. 16] It is important to note, in this statement and throughout the C R T NOPR, that 'transmission owners' are taken to be traditional vertically integrated utilities, and that 'transmission customers' are taken to be sellers of energy, whether utilities, various independent power producers, or power marketers. In undertaking to discuss this proposal, and the claims put forth in the C R T N O P R for its advantages, we understand there to be agreement on the following objectives: 1. reduction of energy costs by moving from a regulated monopoly industry to a competitive market based industry, where energy costs will be determined by free interaction between buyers, producers, and sellers or marketers; 2. equal, non-discriminatory access to the grid for all users - - the meaning of which we will discuss. We assume here that one of the main goals of the N O P R is to establish a set of rules and tariffs which will permit the competitive trading of electric power among buyers and sellers in such a way that each transaction will have equal access to the network without any apriori discrimination or bias;
3. maintenance of reliability of service, to be achieved, inter alia, by an obligation on the part of a transmission grid to provide transmission capacity adequate to supply all connected load ~, (we read this as implicitly according the status of a c o m m o n good to the transmission grid); enforcement of proven industry operating procedures to ensure secure operation of the system, including during contingencies normally considered during the planning process; proper incentives for transmission owners to reinforce the network in a timely manner to facilitate its use in accordance with the foregoing. We take no objection to these objectives perse. However, certain tacit assumptions seem to be made by F E R C as well as by most other parties to the ongoing discussion. We call attention to two of these. The first is that the only entities which have standing in the procedures to be established for ensuring open access to transmission are the various power entities, i.e. the traditional utilities along with the various new independent power producers and power marketers. The second (perhaps not as widely accepted) is that, while recognizing transmission facilities to be a natural monopoly, even within a restructured industry, these facilities should necessarily, within a market driven industry, be priced competitively. In what follows, these two assumptions will be discussed in turn.
3. Transmission capacity and access - -
for whom?
Most if not all of the record of the ongoing debate focuses on generation and transmission providers. Transmission 'customers' are assumed to be power entities, transmission 'providers' are assumed to be vertically integrated utilities, and considerable attention is given to how 'equal, non-discriminatory' access to and use of transmission capacity can be assured to and among utility and non-utility entities. What seems to be overlooked, or precluded from consideration, is that it would be not only valid but more realistic to consider consumers rather than providers of electric power to be the 'customers' of transmission. At the bulk power level, of course, the interface between transmission and load is that between transmission and distribution, with distribution entities, whether traditional distribution systems'., retail brokers, 1The CRT NOPR states that "'The transmission provider is committed to having available enough transmission capacity to serve its native load and the loads of its network customers." [[2], p. 8]
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or other load serving entities, representing (being agents for) the end user, along with large industrial bulk power (high voltage) customers. It is the thesis of this article that if the problem of equal transmission access is viewed from the load perspective rather than from the generation perspective, most of the perplexing problems with regard to assuring non-discriminatory access disappear. 3.1. Transmission access rights
Let us consider the question of to whom transmission access rights (TAR) are most critical, to whom they most naturally pertain, and with regard to which the simplest, most unbiased, and most efficient operation of the market will naturally obtain. 1. Electric energy is generated to satisfy the needs of, and serve the purposes of, the end user who pays the bills - - who supplies the stream of revenue that covers the costs and provides profits for all other entities. (At least for the reasonable future, the end users, other than large, high voltage bulk power customers, will be represented in the market by agents, who may be local distribution companies, or load aggregators, or retail brokers, or other such entities). 2. If TAR were made available to power entities, they would be open to abuse whereby they could be manipulated to the advantage of the power entity who had acquired them, to the detriment of competing power entities and, in the last analysis, of the end users who are paying the bills 2. 3. On this basis, then, it can reasonably be asserted that TAR should pertain to load entities, i.e. the end user who loots the bill or its agent.
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sufficient transmission capacity that all of its connected load could be served reliably under normal and recognized contingency conditions. In other words, the existing transmission was built to ensure that any generation on a given system could be used reliably to serve the loads on that system, and that any foreseeable load on a given system could be served reliably by the generation on the system. These requirements were the dual working out of the traditional 'obligation to serve.' This obligation involved: (a) an obligation to provide sufficient generation to meet, reliably, forecasted loads in aggregate; and (b) an obligation to provide sufficient transmission (and subtransmission and distribution) to deliver that generated energy from the collective generating plant to the individual loads. This dual requirement was refl~ected in the traditional dual reliability analysis, the '1 day in 10 years' criteria applied to generating capacity, and the N-1 criteria applied to network reliability analysis. These capabilities of, and concurrent constraints on, the existing network will not disappear, or change drastically overnight just because of regulatory policy changes or of corporate restructuring. Specifically, each existing load center is connected to enough transmission capacity to ensure that its load can be met reliably by the existing local utility or pool generation plant taken collectively. There is a fair amount of flexibility included in this capacity, but it obviously does not guarantee that any load center can be supplied from any arbitrary future plant on or off the existing utility or pool system. Therefore, while equal, non-discriminatory access to the existing network can be achieved within the constraints imposed by the design of that network, arbitrary access cannot.
3.2. N e t w o r k constraints and transmission access
In considering the question of non-discriminatory access to existing transmission facilities, it is important to note both the capabilities inherent in and the constraints imposed by the existing industry plant and its environment. The existing transmission network was designed and built to ensure two capabilities: (i) to ensure that the generation of existing plants, as they were built, was provided with sufficient transmission capacity to assure that it would not be 'bottled up,' i.e. that the full generating output of the plant could be delivered to the network for transmission to the system load centers; (ii) to ensure that all (each and every) load center (or distribution substation) was provided with 2,,in the UK, competition has prompted players to seek out crevices in the rules to maximize their returns,..." [4] We suggest it would be naive to expect it to be otherwise.
Predictions of radically different power flow patterns on the network in the near term are unrealistic, for the simple reason that the network will not support radically different patterns other than at a fraction of its design capacity. No policy can change this, only future construction. Therefore, equal, non-discriminatory access can be realized only to the extent possible under these constraints. It should be noted that such constraints have applied to the traditional operation of the system. Many utilities have been constrained in applying optimal economic dispatch procedures by system bottlenecks they have been unable to remove due either to inability to secure necessary rights-of-way or to other obstacles beyond their control. These constraints do not mean that there is no flexibility in the present system. Since the network was designed to meet any foreseen network load under economic dispatch (in so far as possible, with necessary
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exceptions), any load can be supplied from a variety of sources on and off the network; it is just that that variety is not unlimited. It is also to be emphasized that, not only is any load center connected to sufficient network capacity to meet its requirements, it is also assured of this capability under all foreseen simultaneous loads of other load centers on the same system. Therefore, if each load center were to be assigned the rights to the existing access it already enjoys by virtue of the design of the network, and could utilize these rights in entering into transactions with any and all generating sources whose bids it finds to be attractive, there would be no need for any power entity to acquire access rights for each proposed transaction. This situation means that the objective of equal (or non-discriminatory) access could be achieved, now and in the future as the network is reinforced, much more directly and efficiently, by assigning TAR to load serving entities than by assigning them to 'nominating' generators or marketers, or seriatim to proposed transactions. 3.3. Capacity reservations 3
We suggest that assigning of T A R to power entities entails significant disadvantages and hazards to efficient operation of the market, because of which numerous cumbersome and potentially ineffective rules must be instituted - - many of which are set forth in the NOPR. It would be highly discriminatory for a power entity to reserve transmission capacity without specifying to which load or loads this power is intended. Such a reservation would violate the basic principle of equal access to the network if some loads were obliged apriori to buy power from a given generator only because it reserved and monopolized enough transmission capacity 4. In other words, if, by unconditionally reserving transmission capacity, a power entity prevents certain loads from having access to other possibly cheaper generation, this constitutes a discriminatory reservation through the monopoly of the network, an action that would be against the interest of both loads and generators. 3 In discussing 'reservations,' it is not always clear when or whether the C R T N O P R is dealing in the operations planning time frame (hours to months), or in the system planning time frame (years). We will attempt to discuss 'reservations' in the former, and 'transmission reinforcement' in the latter time frame. In either case, some considerations are the same, but not in all cases. 4 Presumably, moving to market competition is to enable end users to benefit from lowest available cost energy, not to enable suppliers to gain advantages over competitors so they can reduce customer access to transmission.
Effecting a transaction involving the sale/purchase and delivery of power from a power entity to a load entity requires the use of a greater or lesser portion of a transmission network connecting the two parties. Where there are many power entities and many load entities, the potential number of 'paths' between pairs of sellers and buyers becomes huge. If transmission access is sought after agreement on a transaction has been reached, then the agreement may have to be renegotiated or voided if the righls cannot be obtained; if the rights are confirmed prior to an agreement, multiple generators may be seeking rights for the same or related transactions, causing apparent congestion. In either case, the number of studies required could be exorbitant. If, alternatively, transmission access is sought by each interested provider on behalf of the intended receiving load entity, then this is tantamount to assigning the access right to that load entity, except that it involves multiple competing 'nominations' in lieu of one. Under the proposed free market in e,nergy, the 'load' of (i.e. energy drawn from) any generator may be very volatile, in response to changing market conditions, whether viewed from the short term or over a longer term. In order to have enough T A R to serve any potential customers, any given power entity must have rights that are necessarily redundant vis-a-vis those of its competitors. In the course of the functioning of the market, such rights will have to be re-assigned from one generator site to another (unless the network is ridiculously overbuilt to an extent the national economy could not support), and such reassigning will hold potential for game playing by power entities whereby they will seek market advantages over competitors to the extent of curtailing equal access of load entities to the lowest potential market prices for needed power. Both primary and secondary markets will have to be established, regulated, monitored, with increasingly complex rules enforced, penalties defined and imposed, ad nauseam. It is a significant fact, however, that energy required by load sites will remain much more stable than will loads served by generating sites. This is because loads cannot arbitrarily be transferred from one geographical (or to any significant extent, from one electrical) site to another, whereas the generator serving a given load may, and often is, freely 'dispatched' from one generating site to another, perhaps very distant, one. The (local) transmission capacity required to serve a given load site is a known, slowly varying: quantity. The existing transmission grid has been (and any future
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development of the grid must be) designed and built to accommodate the needs of given load sites for energy. Thus, if T A R are viewed vis-a-vis load entities, the need for those rights, in each case, is a relatively known, stable, quantity. The network has been built, and over time has been and should continue to be, reinforced to satisfy those needs. If a load entity wishes to procure the lowest priced energy at any point in time, and if it has been assigned T A R to the transmission capacity that was built into the system to satisfy its requirements, then it will be free to shop among all available power entities (subject to security constraints, to be discussed later), and apply, to any transaction into which it wishes to enter, sufficient capacity rights to effect and complete that transaction. No game playing is involved, no secondary market, no infringement on free access of load entities to cheapest available power except by the physical constraints that dictate secure operation. The discussion thus far has propounded a concept, termed 'load entity transmission access rights,' (LTA) that provides an alternative to that of the CRT NOPR, and that we believe comes much closer to achieving the objectives and meeting the relevant criteria. It is evident, of course, that under severely congested conditions (beyond design parameters), any capacity reservation, even for a transaction between a generator and a load, can be implemented only at the expense of other transactions. This justifies the concept of a proposed transaction. Only after some security-monitoring entity approves a proposed transaction from the perspective of system security, does it become a reserved transaction. In most cases, however, in most parts of the country, approval by the security monitor will be pro forma, obviating the need for much complex realtime analysis.
4. T a r i f f - -
c o m m o n g o o d or m a r k e t basis?
Transmission tariffs necessarily reflect the status that is accorded to the transmission network. Unless its status as a common good is given priority, that status could very well be rendered nugatory by an inappro priate tariff. 4.1. Incentives for transmission system reinforcement and expansion
The CRT N O P R raises an implicit question of the role of transmission grid as a player in a competitive supply/demand market process. As implied by the interdependence of tariffs and network status, different incentives will result from the network's being treated as a regulated common good monopoly, or a regulated
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market based monopoly. The former status, with its attendant obligation to provide transmission service to all connected loads, would seem necessarily to require the traditional regulated rate of return on investment to ensure ongoing provision of adequate facilities. The latter status suggests market incentives that will lead to minimum cost economically efficient expansion within regulated capped rates, but would necessarily subordinate an 'obligation to provide access' to an 'ability to pay' (which would be counter to the motivations for establishment of the Rural Electrification Administration in 1936) 5. Unfortunately, in addressing this issue, we are faced, prior to any technical issues, with the imponderable ethical issue of fairness, of an obligation to serve versus a commitment to market efficiency. This issue will be resolved ultimately in a political context. Let us consider the implications of treating transmission as a common good. For traditional regulated utilities under an obligation to serve, regulated recovery of costs to meet revenue requirements (rate-of-return on investment) have proven effective in assuring robust reliable systems, to the extent that some have argued at times that such systems have been 'gold plated.' In view of the uncertainties that await the electric energy industry in the restructured future, as well as the requirements for open access to competing power entities, it may well be that such an incentive struclure may be necessary to ensure adequate transmission capacity. The LTA paradigm could accommodate a variety of tariff structures. Perhaps the simplest approach, and most consistent with traditional practice, fbllows from continued recognition of the transmission entity, per se, as still being a common good, as well as a regulated natural monopoly.
The approach to transmission access rights in this article implies that the load entities will acquire those rights by virtue of the transmission network having been designed to provide access adequate to their needs, and, a corollary, that they should pay for that access according to the traditional regulated utility formula based cost-based revenue requirements. Access rights of a load entity to the local transmission network would be provided in proportion to the coincident peak load of that entity (within its region). For native load entities, the (regulated) transmission tariff would contain a fixed and a variable (load dependent) component. The fixed component would be calculated (as have been traditional regulated utility rates) to 5 It is relevant to note that deregulation of the airline and railroad industries has resulted in withdrawal of air and rail service from widespread rural areas of the US
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recover all fixed costs plus an approved rate of return on investment (the revenue requirement) based on the coincident peak load demand of the connected load portion of all entities serving loads on that transmission system. The additional variable portion of the fee would then include any network related ancillary service charges, including, for instance, transmission loss charges, a charge for other network related expenses such as purchased reactive energy, purchased power to cover transmission losses, etc. It would be possible to augment this structure by a congestion related component that would relieve congestion via appropriate price signals. It is important to note that, in this traditional approach, as a regulated monopoly with tariffs calculated to provide a recognized rate-of-return on investment, the transmission entity would have the same incentive as led the traditional industry to provide capital intensive, robust, reliable systems. Transmission expansion under any scenario requires forecasting-based planning. The C R T N O P R alludes in several places to considerations of planning system reinforcement and expansion, and the advantages of the CRT framework in this connection. For instance, it states that "the transmission provider knows only the customers' historical loads, not their future loads... The transmission provider may not have any good way to forecast the increase or decrease in the loads of customers it has no obligation to serve" [[2], p. 81]. This means that the utility who is the transmission provider can forecast the growth of those portions of its connected load who still purchase their energy from it, but they cannot forecast the growth of loads connected to its system that are purchasing their energy from other power entities. But this is beside the point. So far as its 'native load' (in this restricted sense) is concerned, that load is no longer captive, as in the past, and presumably any or all of it may choose, tomorrow-, to become the load of some other provider. This observation also pertains, pari passu, to the other power entities that are involved their future load is no more predictable than the transmission providers. -
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What is still true, however, as true as in the past, is that the connected load on the transmission provider's system is still as predictable, though no more predictable, than it has been in the past, and the transmission entity should still be as able to forecast that load for the purposes of reinforcing its network as its utility predecessor was in the past. The CRT N O P R recognizes in one or more places that there may be problems in arriving at an optimal
expansion of the system through basing it on the forecast needs of relevant power entities. For instance, it states that "an argument can be made that the CRT approach may lead to an understatement of A T C " [[2], p. 9]. This is equivalent to saying it could lead to an over statement of the need for additional capacity, and is quite true, since competing power entities would be forecasting redundant needs, each hoping to attract some of its competitors' customers. Under the LTA paradigm proposed in this response, however, this is not the case. Under this paradigm, as already explained, the transmission entity would forecast the need for system reinforcement to meet the needs of its connected load, which is equivalent to what utilities have done in the past. What will be more difficult to predict will be the location of future generation, since this will now be decided by the influence of market forces on a variety of individual third party, existing or future, power entities. However, it will be to the advantage of power entities to keep the transmission provider fully aware of their future plans, so that the information available to the transmission provider will be nearly as good is it was in the past to the predecessor utility.
4.2. Wheeling and parallel flows Access to off-system (outside the host transmission system) capacity requires different treatment. The argument thus far has been that load entities have already paid for much of of the transmission facilities built to serve their demand (i.e. what's already been depreciated), and that those load entities should continue to pay for such facilities in the same manner, i.e. via a regulatory-approved required revenue based tariff. Use of the local grid by 'foreign' generation presumably would be in order to serve local load. Thus there is no essential difference in use of the network. However, for wheeling, the story is different. Since capital investment in the network would be recovered under the native load tariff, wheeling access granted to off-system entities, to the extent that they did not infringe on access requirements of native loads, could be granted on an implicitly reciprocal basis, with charges confined to reimbursement for necessary ancillary services including losses proportional to the imposed flows. If multiple, conflicting requests were involved, they could be granted on the basis of some form of a variable, transaction related charge, payable to the network(s) involved. (In the interests of effectiveness, these charges should probably be passed through some central clearing house, perhaps a role of the local transmission entity.) Since these TAR would be subsidiary to the native rights of load entities within each system, they would be acquired via the market at market clearing price.
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The handling of parallel flows is, as well known, a matter of much debate. This is not the occasion on which to muddy the waters, as it is not central to the present discussion. However, as an aside, in view of the complexity of all proposed solutions for providing even approximately correct distribution of costs, consideration should be given to appropriate zoned fares. If the overall network were divided into appropriate electrical zones, it would be fairly straightforward ex ante to determine by load flow what fraction of a transaction would flow across which zones, and ex post to apportion wheeling charges proportionately. Since this would be done considering only the transaction involved, in the absence of other flows, it would be approximate, but should be a fair attribution of costs over the long run for large numbers of transactions. As the system evolves from here on out, under open access, with new flow patterns emerging that require reinforcement of the grid beyond what is required to serve local loads, then such reinforcement could and should be provided by the transmission entities under a different tariff that would recognize and compensate those entities for the risk that would be involved. An attractive mechanism for this purpose would be a peak load pricing formula [6]. Such reinforcements should be excluded from the rate base used for determining loadserving-entity base tariffs, and should be paid for under the peak-load pricing rates applied to wheeling contracts, on a case by case basis. Such practice would make very clear when (and over what distances) wheeling is really economical. Also to be considered is the possibility that evolution of the system may be such as to actually reduce loading of the network if the technology and economics are such as to lead to construction of a great deal of low cost, dispersed generation sited close to loads! This would be a reversion to earlier patterns of system use. In the 1950's, it was not uncommon for bulk power systems to be lightly loaded, since they served only to provide a reserve for emergency capacity transfers. In the case of congestion, zones who suffer from the effects of parasitic flows should be reimbursed by the transactions causing those flows. Zoned tariffs could also serve to utilize market forces to relieve congestion. Escalation of the variable portion of the tariff within congested zones as loads increased would encourage modification of transactions to alleviate congestion, if the use of those tariffs were restricted to such use [7].
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requested ('nominated') access. However, in order to discuss capacity rights, it is essential to account explicitly for the various network limitations defining system security, namely, transmission flow limits, N.-1 security, voltage and reactive power bounds and stability. System security must be an integral part of the definition of transmission capacity and not a secondary service. It should be emphasized that the set of security limits of a power network is what defines its transmission capacity. Security is a complex multi-dimensional property of power networks, and hence, so is transmission capacity. Transmission capacity cannot and should not be treated as a one-dimensional quantity, and certainly not as a linear property to which superposition applies. Transmission capacity depends on: (i) the values of numerous network variables and parameters; (ii) which power transaction is being considered; and (iii) the levels of every other network transaction taking place simultaneously. Some transactions may stress network security only slightly, while others will quickly lead to the saturation of certain lines or to other security limits. Therefore, available transmission capacity will vary drastically from one transaction to another. The physical factors that characterize the security region for the network (i.e. the set of all possible operating points that do not violate any security constraint) are inherent in the network topology and the characteristics and condition of its components, and cannot be changed by operating practices, although their becoming active may be circumvented under some circumstances, to a certain limited extent and at a cost. The necessity of maintaining secure operation of the system vis-a-vis potential disturbances is responsible for much of the difficulty involved in evaluating and allowing or disallowing potential transactions. This is not the time to write a manual on power system security assessment. Suffice it to say that N-1 security (the ability of the system to ride through loss of any one major component without violating stated security constraints) and its derivatives require voluminous dynamic as well as steady state analyses of system responses in its current or in many projected operating states, to any one or selected combinations of 'credible' disturbances. On a large system, the dimensionality of this task can be overwhelming. 5.1. Security constraints
5. Secure system operation The concept of transmission capacity presented in the N O P R does not explicitly refer to the necessity of satisfying power system security, although it is implicit in the requirement for approval of ('reserving') any
If security assessment is to be carried on effectively within a restructured industry, it is not only prudent, but necessary to build on present adequate (admittedly not ideal) practice rather than prescribing some new, unproven solution to a problem that is becoming more,
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rather than less complex 6. Due to the complexity and overwhelming computational effort involved in analyzing system security in real time, utilities have been forced to develop approximate (and therefore conservative) methods for real-time security assessment.
burdensome, closer to proven accepted power system practice, and hence more feasible and to be preferred over the generator-referenced alternative.
It will be highly desirable, initially, to make new practice as compatible as possible with present proven practice.
Much of the foregoing discussion has focused on the inherent rights of load entities to access local transmission capacity. It is recognized, however, that increasingly now for some time, energy transactions span greater distances, crossing one or more transmission entity boundaries in the process. (For the purposes of this present discussion, we are assuming that transmission entity boundaries coincide with existing control area boundaries.) Thus the concept of transmission access rights (TAR) transcends that of load entities to their local networks.
For instance, current practice with regard to security constraints often is based on sets of limiting flows across critical boundaries, and dispatch and interchange transactions are permissible so long as these constraints are not violated. Under current practice, these constraints are conservative, but necessarily so because updating the numerous calculations that are involved is not possible in real time. If this practical necessity of current practice is acknowledged (as it must be), then new procedures should build on this practice as far as possible. Such practices can then be extended to accept less conservative, more up-to-the-moment constraints as their calculation becomes feasible. For any generator (exporter) to put together and acquire TARs for transactions to sell its available energy, it would have to calculate, or have calculated, a very large number of case studies showing that import limits of all potential buyers will not be violated in the face of all existing or possible transactions (possibly involving many of the same potential buyers) desired to be entered into by competitors. For this it would be dependent on the network security monitor. Providing such monitoring for all power entities for all desired transactions (sales) would be so formidable as to approach infeasibility in real time unless it is done very conservatively. A different constraint is likely to apply to each proposed transaction, and to be a volatile function of all other simultaneous transactions. For any load entity (importer) to know the security constraints affecting any proposed purchase from any potential supplier, it can be calculated with a good degree of (conservative) accuracy on the basis of precalculated, periodically updated interface flow constraints provided by the network security monitor. A given constraint is likely to apply to a large set of possible transactions of potential interest, and to be affected by another large set of possible transactions collectively rather than individually. Thus, this load-referenced procedure is prima facie more direct, less computationally 6A leading industry expert [5J has recently pointed out the difficulties that have bedeviled the EMS (energy management system) industry in supplying state of the art software adequate to the needs of the current state of the industry.
5.2. Wheeling, parallel flows, and congestion
The use of neighboring, and more distant, networks in order to implement a transaction will require access to transmission facilities to which the load entities (as well as the generating entities) involved have no inherent rights. Two major questions immediately arise in these situations: that of contract or other paths that are involved when importing power from off-system sites, and that of the parasitic parallel (or loop) flows that affect portions of the larger network that are not directly on the contract path.
5.2. I. Wheeling Again, in this context, we need to consider: (i) who should be eligible, or responsible for acquiring TAR in such cases; and (ii) how should such :rights be paid for? It has already been stipulated that, in these cases, the load entities as well as the generating entities involved have no inherent rights. However, in recognition of the fact that it will always be the end user who pays the bill, as well as in the interests of uniformity, it is suggested that in this case also (i.e. the case of acquisition of off-(local)-system transmission rights for effecting a given transaction), it should be the buying (load) entity who acquires those rights. This eliminates any chance of unproductive overhead charges being added to the transaction, it reduces if not eliminates the need to consider multiple TAR during the negotiation process (since load entities will be aware of the critical interfaces at which they still have some margin, and will shop amongst potential suppliers with those interfaces in mind), and will eliminate the need, which has been discussed earlier, for multiple potential suppliers to vie for transmission capacity needed to effect the proposed transactions, and obviate possibilities for gaming on the part of power entities to gain competitive advantages vis-a-vis load entities.
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5.2.2. Parallel flows If T A R are considered in terms of flows across critical interfaces as defined by before the fact load flow analysis, then the problem of treating parasitic parallel flows becomes that of the treatment of congestion imposed on, and of compensation for, all the transmission entities whose networks are affected by a given transaction.
5.2.3. Congestion Congestion arises when the network is loaded close to its capacity, and the (conservative) security constraints on flows across critical interfaces become inadequate criteria. In such cases, it becomes necessary for the transmission security monitor (who in some proposals will be an ISO) to treat proposed transactions on a one-by-one basis. Three cases should be considered: (i) when the congestion is due to generally heavy loads on the system; (ii) when the congestion is caused by requests for wheeling through a given system; and (iii) when the congestion is caused by parasitic parallel flows due to wheeling on adjacent systems. In each of these cases, it will be necessary to disallow or impose modifications on proposed transactions, but the criteria will be different in each case. In the first case, general congestion due to high loads, it may or may not be the case that native load entities will be exceeding their coincident peak load requirements. In either case, the network security monitor will have to: (i) treat proposed transactions according to the principle that the native load entities are entitled to use of the system proportionate to their coincident peak load requirements; and (ii) modify transactions, on a case-by-case basis, in such a way as to maintain this proportionality. The effect may be that one or more load entities will be forced to forego access to the lowest cost generation. In principle, the trading of reserved transmission capacity among transactions is feasible, however, this is severely complicated by the fact that reserved transmission capacity is not additive [[2], pp. 8, 9] but rather highly non-linear 7. Trading of reserved transactions could take place but would be highly dependent on relative MW levels and market values of each transaction and it would have to be approved by the security monitor to ensure that security was satisfied. In the second case, when the congestion is caused by requests for wheeling through a given system, it will be necessary to recognize the priority of native loads to 7 Thus, under congestion, cases can arise where the reduction of a given reserved transaction by 1 MW permits another transaction to be increased by only 0.5 MW so that, in order to meet the load, a third or perhaps more transactions would have to be modified.
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access to their local transmission system. It would be inequitable to force load shedding, or even otherwise unnecessary increases in energy costs, on local loads (who, through their tariffs, are paying for the local transmission capacity) for the benefit of foreign users. In the third case, when the congestion is caused by existing parasitic parallel flows due to wheeling on adjacent systems, to the extent that such loading precludes access of native load to low cost energy, they should be reimbursed for their higher costs; by parties causing the parasitic flows.
6. Summary: a new paradigm
The network was designed and built to provide unbottled generation access and adequate local service simultaneously to all load centers under forecast normal and recognized emergency conditions. Needs of loads for transmission access are known and stable, and are not volatile vis-a-vis individual transactions. To the extent that they are compatible with the requirements of other load centers, each load's needs may be satisfied within network constraints. For any load to seek access outside these constraints would violate the rights of other loads to equal access. The CRT N O P R [[2], p. 8] suggests that putting all users (by which they mean power entities) on a reservation basis appears to be compatible with the new OASIS and the requirement that market ]participants know how much transmission is available for their use. We suggest that recognizing that load entities have an inherent access right to the transmission capacity that was designed and built to ensure satisfaction of their load requirements, making known to all market participants what are the current security constraints that dictate how much energy may be imported across given interfaces into that entity's region, then the market participants do know how much transmission is available for their use. The relevant market participants in this case are the load entities, since they a:re free, and are entitled, to import for their load energy from the lowest cost (or other preferred) power entity subject only to non-violation of stated and published security constraints. Thus, load entities always have 'reserved' that portion of the network capacity serving their region that is required to satisfy their requirements under all but extreme emergency conditions. The C R T N O P R suggests that the C R T policy will satisfy a variety of objectives and provide numerous advantages over alternatives. We believe we have shown that there are numerous significant economic and operational advantages to develop a tariff based: (i) on transmission entities who have no incentive or opportunity for viewing or treating any source of power connected to their network any differently from any
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other source of power on or off their network; and (ii) on assigning T A R to load entities, not to power entities. The N O P R states ([2], p. 6) that, "in adopting the Final Rule tariff in the Open Access Final Rule, our purpose was to remedy undue discrimination in the provision of interstate transmission service, not to reform traditional tariff design." In this and other statements throughout, the emphasis is on remedying (or avoiding) undue discrimination by transmission providers who are in fact generating utilities against other power entities who are not transmission providers. We suggest that this is insufficient to meet the objective of providing free play of the market among all participants, not just power entities. The C R T N O P R [[2], p. 14] suggests that " I t would appear that transmission service would be fully unbundled from generation service under a C R T because the generation and transmission products are reserved and used independently." We suggest, rather, that by assigning T A R to power entities, regardless of how level the playing field (or market) might be by means of which those rights are sought (nominated) and obtained (reserved), generation and transmission are de facto rebundled vis a vis the end user, and that the equal access rights of the demand side of the market (load, or load-serving, entities) is subject to violation. In general, once a power entity has obtained T A R , to some extent the access of other power entities to equivalent rights is limited. This is not necessarily objectionable so far as equity among power entities is concerned, since the rights were obtained by fair competition. However, it is very objectionable with regard to load entities because it restricts their equal access to all potential power suppliers, and to that extent the market power provided by bundled generation and transmission (G and T) vis-a-vis load entities re-emerges. Assigning of T A R to generators would inevitably lead to the proliferation of byzantine rules, regulations, oversight, and penalties in the attempt to ensure a level playing field of equal access for all parties. This is because generators would have implicit motivation/incentive to game the system in such way as to maximize their own access and minimize their competitor's access. The end result would seem to be to develop a 'seller's market,' wherein de facto recombination of generators with transmission facilities, albeit under new
competitive realignment of players, would reflect collectively, in some way, the status quo ante of the industry, with room for jockeying (and game playing to obtain advantages) a m o n g the generators. Load entities would have no such incentives, being only concerned with assured access to sufficient transmission capacity to meet their own needs. Thus, assignment of T A R to load serving entities would even the playing field between buyers and sellers, tending if anything toward a buyer's market, with advantages toward the end user. In comparing load (LTA) versus generator (CRT) transmission access rights, we suggest that, under load access: load is assigned T A R to match its (coincident peak) requirement; there is no need for a secondary market; transmission stranded cos~Ls are eliminated; non-discrimination is extended to encompass load as well as power entities; flexible shifting of generation is inherent; economic efficiency in network reinforcement is inherent, since necessary expansion is rewarded without any incentive for overexpansion. Conversely, under generator access: discrimination vis-a-vis load entities is inherent; power entities are given advantage over potential customers; there is an inherent tendency toward inefficient overbuilding of the network, since competing generating entities may attempt to nail down (redundant) capacity adequate to serve customers they hope to get!
References
[1] Federal Energy Regulatory Commission: Promoting wholesale competition through open access non-discriminatory transmission services by public utilities, Order No. 888, Final Rule 24, April 1996 (Docket Nos. RM95-8-000 and RM94-7-001). [2] Federal Energy Regulatory Commission: Capacity reservation open access transmission tariffs: notice of proposed rulemaking, 24 April 1996 (Docket No. RM96-11-000). [3] L.H. Fink, Ancillary transmission services, Electr. J. 9 (5) (19961 18-25. [4] R.D. Tabors, Lessons for the UK and Norway, lEEE Spectrum 33 (8) (1996) 45- 49. [5] R.D. Masiello, It's put up or shut up for grid controls, IEEE Spectrum 33 (8) (1996) 50. [6] B. Lecinq, M.D. Ilic, Peak-load pricing for electric power transmission. J. Regul. Econ. (submitted). [7] M.D. Ilic, F. Graves, Optimal use of ancillary generation under open access and its possible implementalion. TR 95-006, Mass. Inst. of Technol. Lab. for Electromagnetic and Electronic Systems. August 1995.
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ELECI'fllC COWER 8 STlm8 R|$EnRCH
Transmission access rights and tariffs Lester H. Fink a.,, Marija D. Ilic b, Francisco D. Galiana c KEMA Consulting (retired), 250 Pantops Mountain Road, Box 4, Charlottesville VA 22911, USA b Massachusetts Institute of Technology, Cambridge, MA 02139, USA c McGill University, Montreal, Quebec, Canada Received 4 March 1997
Abstract Much of the current debate in the US surrounding the deregulation of electric power supply and the associated restructuring of that heretofore vertically integrated industry has been concerned with measures to nullify or eradicate any market power based on control of access to transmission by the traditional utilities. The debate has had to do with various degrees of 'unbundling' of control of the two assets (generation and transmission) in order to ensure that all power suppliers - - various types of independent power producers and power marketers - - have access to transmission that is as unfettered as that of the owners. The argument of this paper is that any assigning of transmission access 'rights' to power suppliers of any ilk is de facto a 'rebundling' of what it has been desired to 'unbundle.' In addition, assigning transmission access rights to suppliers is bound to inflate the demand for transmission capacity, whether in the short or the long run, because multiple suppliers will seek to secure access rights for prospective transactions for which they are competing. An alternative approach is suggested, based on the facls that existing transmission has been provided to ensure adequate and reliable supply to existing loads, that the relation of transmission capacity and loads is stable (whereas the relation of supply and loads, and hence of supply and transmission will be increasingly volatile), and that transmission constraints have conventionally been defined and monitored in terms of imports (to loads) across critical interfaces (cut sets). From this perspective, assigning of transmission access rights to loads (as their proportionate share of imports across critical interfaces), and charging for such access in the traditional mode of regulated return-on-investment: tariffs would avoid almost all the difficulties hobbling the current debate. © 1997 Elsevier Science S.A.
Keywords: Power system transmission access; Power system restructuring; Power system transmission tariffs
1. Introduction In the course o f its o n g o i n g fostering o f the restructuring o f the nation's electric energy industry, the Federal Energy Regulatory Commission ( F E R C ) has released, in parallel, an Order and a further Notice o f P r o p o s e d Rulemaking ( N O P R ) . Order 888 [1], which m a n d a t e s opening o f utility transmission lines to competitors, includes a pro f o r m a tariff providing terms and conditions. The N O P R [2] proposes to replace that pro f o r m a transmission tariff with a new capacity reservation tariff (CRT). Distributed t h r o u g h o u t the C R T N O P R are statements setting forth n u m e r o u s ad-
* Corresponding author. Tel.: + 1 804 9809344; fax: + 1 804 2967450; e-mail: [email protected] 0378-7796/97/$17.00 ~' 1997 Elsevier Science S.A. All rights reserved. PIIS0378-7796(97)01181-4
vantages o f the p r o p o s e d C R T . We question certain assumptions that seem implicitly to underlie the C R T , and fear consequently that some o f the alleged advantages are illusory. We believe further that correction o f the implicit assumptions can lead to an alternative p a r a d i g m that would actually provide :many of the advantages claimed for the C R T . In an earlier article [3], a case was put forth for recognizing the obligations o f loads relative to requirements for ancillary services. In this article., a case is put forth for recognizing the rights o f loads relative to equal presence at the table where the market functions. Based on our c o m m e n t s submitted to F E R C in response to the C R T N O P R , we identify assumptions we believe to be underlying that N O P R , :motivate and outline our alternative paradigm, and indicate what we see to be its n u m e r o u s advantages.
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2. Background
The ostensible objective of the flourishing reconceptualization of the electric energy industry (the industry) that is currently in process is the reduction of energy costs to end users by replacing a regulated monopoly industry by a competitive free market industry. A prominent feature of the resulting transformation of the industry is the emergence of a variety of new power producing and power marketing entities in competition with the traditional utilities. A major focus of the activities of the Federal Energy Regulatory Commission (FERC) has been to preclude the entrenched utilities from using their market power and control of the existing transmission networks to the disadvantage of the new entities. This latter aim is being fostered by putting in place various requirements intended to insure open access to bulk power transmission facilities on the part of the new entities. These objectives necessarily are to be achieved without endangering the traditional proven reliability of the industry in the US. The essence of the capacity reservation tariff concept put forth in the C R T N O P R is stated as follows: " U n d e r the CRT, which would replace existing transmission tariffs, all firm transmission users, including the transmission owner on behalf of its wholesale requirements and bundled retail customers, would nominate and reserve transmission capacity; they would nominate and reserve firm rights to receive specific amounts of power at specific grid PORs [points of receipt] and to deliver specific amounts of power at specific grid PODs [points of delivery]." [[2], p. 16] It is important to note, in this statement and throughout the C R T NOPR, that 'transmission owners' are taken to be traditional vertically integrated utilities, and that 'transmission customers' are taken to be sellers of energy, whether utilities, various independent power producers, or power marketers. In undertaking to discuss this proposal, and the claims put forth in the C R T N O P R for its advantages, we understand there to be agreement on the following objectives: 1. reduction of energy costs by moving from a regulated monopoly industry to a competitive market based industry, where energy costs will be determined by free interaction between buyers, producers, and sellers or marketers; 2. equal, non-discriminatory access to the grid for all users - - the meaning of which we will discuss. We assume here that one of the main goals of the N O P R is to establish a set of rules and tariffs which will permit the competitive trading of electric power among buyers and sellers in such a way that each transaction will have equal access to the network without any apriori discrimination or bias;
3. maintenance of reliability of service, to be achieved, inter alia, by an obligation on the part of a transmission grid to provide transmission capacity adequate to supply all connected load ~, (we read this as implicitly according the status of a c o m m o n good to the transmission grid); enforcement of proven industry operating procedures to ensure secure operation of the system, including during contingencies normally considered during the planning process; proper incentives for transmission owners to reinforce the network in a timely manner to facilitate its use in accordance with the foregoing. We take no objection to these objectives perse. However, certain tacit assumptions seem to be made by F E R C as well as by most other parties to the ongoing discussion. We call attention to two of these. The first is that the only entities which have standing in the procedures to be established for ensuring open access to transmission are the various power entities, i.e. the traditional utilities along with the various new independent power producers and power marketers. The second (perhaps not as widely accepted) is that, while recognizing transmission facilities to be a natural monopoly, even within a restructured industry, these facilities should necessarily, within a market driven industry, be priced competitively. In what follows, these two assumptions will be discussed in turn.
3. Transmission capacity and access - -
for whom?
Most if not all of the record of the ongoing debate focuses on generation and transmission providers. Transmission 'customers' are assumed to be power entities, transmission 'providers' are assumed to be vertically integrated utilities, and considerable attention is given to how 'equal, non-discriminatory' access to and use of transmission capacity can be assured to and among utility and non-utility entities. What seems to be overlooked, or precluded from consideration, is that it would be not only valid but more realistic to consider consumers rather than providers of electric power to be the 'customers' of transmission. At the bulk power level, of course, the interface between transmission and load is that between transmission and distribution, with distribution entities, whether traditional distribution systems'., retail brokers, 1The CRT NOPR states that "'The transmission provider is committed to having available enough transmission capacity to serve its native load and the loads of its network customers." [[2], p. 8]
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or other load serving entities, representing (being agents for) the end user, along with large industrial bulk power (high voltage) customers. It is the thesis of this article that if the problem of equal transmission access is viewed from the load perspective rather than from the generation perspective, most of the perplexing problems with regard to assuring non-discriminatory access disappear. 3.1. Transmission access rights
Let us consider the question of to whom transmission access rights (TAR) are most critical, to whom they most naturally pertain, and with regard to which the simplest, most unbiased, and most efficient operation of the market will naturally obtain. 1. Electric energy is generated to satisfy the needs of, and serve the purposes of, the end user who pays the bills - - who supplies the stream of revenue that covers the costs and provides profits for all other entities. (At least for the reasonable future, the end users, other than large, high voltage bulk power customers, will be represented in the market by agents, who may be local distribution companies, or load aggregators, or retail brokers, or other such entities). 2. If TAR were made available to power entities, they would be open to abuse whereby they could be manipulated to the advantage of the power entity who had acquired them, to the detriment of competing power entities and, in the last analysis, of the end users who are paying the bills 2. 3. On this basis, then, it can reasonably be asserted that TAR should pertain to load entities, i.e. the end user who loots the bill or its agent.
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sufficient transmission capacity that all of its connected load could be served reliably under normal and recognized contingency conditions. In other words, the existing transmission was built to ensure that any generation on a given system could be used reliably to serve the loads on that system, and that any foreseeable load on a given system could be served reliably by the generation on the system. These requirements were the dual working out of the traditional 'obligation to serve.' This obligation involved: (a) an obligation to provide sufficient generation to meet, reliably, forecasted loads in aggregate; and (b) an obligation to provide sufficient transmission (and subtransmission and distribution) to deliver that generated energy from the collective generating plant to the individual loads. This dual requirement was refl~ected in the traditional dual reliability analysis, the '1 day in 10 years' criteria applied to generating capacity, and the N-1 criteria applied to network reliability analysis. These capabilities of, and concurrent constraints on, the existing network will not disappear, or change drastically overnight just because of regulatory policy changes or of corporate restructuring. Specifically, each existing load center is connected to enough transmission capacity to ensure that its load can be met reliably by the existing local utility or pool generation plant taken collectively. There is a fair amount of flexibility included in this capacity, but it obviously does not guarantee that any load center can be supplied from any arbitrary future plant on or off the existing utility or pool system. Therefore, while equal, non-discriminatory access to the existing network can be achieved within the constraints imposed by the design of that network, arbitrary access cannot.
3.2. N e t w o r k constraints and transmission access
In considering the question of non-discriminatory access to existing transmission facilities, it is important to note both the capabilities inherent in and the constraints imposed by the existing industry plant and its environment. The existing transmission network was designed and built to ensure two capabilities: (i) to ensure that the generation of existing plants, as they were built, was provided with sufficient transmission capacity to assure that it would not be 'bottled up,' i.e. that the full generating output of the plant could be delivered to the network for transmission to the system load centers; (ii) to ensure that all (each and every) load center (or distribution substation) was provided with 2,,in the UK, competition has prompted players to seek out crevices in the rules to maximize their returns,..." [4] We suggest it would be naive to expect it to be otherwise.
Predictions of radically different power flow patterns on the network in the near term are unrealistic, for the simple reason that the network will not support radically different patterns other than at a fraction of its design capacity. No policy can change this, only future construction. Therefore, equal, non-discriminatory access can be realized only to the extent possible under these constraints. It should be noted that such constraints have applied to the traditional operation of the system. Many utilities have been constrained in applying optimal economic dispatch procedures by system bottlenecks they have been unable to remove due either to inability to secure necessary rights-of-way or to other obstacles beyond their control. These constraints do not mean that there is no flexibility in the present system. Since the network was designed to meet any foreseen network load under economic dispatch (in so far as possible, with necessary
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exceptions), any load can be supplied from a variety of sources on and off the network; it is just that that variety is not unlimited. It is also to be emphasized that, not only is any load center connected to sufficient network capacity to meet its requirements, it is also assured of this capability under all foreseen simultaneous loads of other load centers on the same system. Therefore, if each load center were to be assigned the rights to the existing access it already enjoys by virtue of the design of the network, and could utilize these rights in entering into transactions with any and all generating sources whose bids it finds to be attractive, there would be no need for any power entity to acquire access rights for each proposed transaction. This situation means that the objective of equal (or non-discriminatory) access could be achieved, now and in the future as the network is reinforced, much more directly and efficiently, by assigning TAR to load serving entities than by assigning them to 'nominating' generators or marketers, or seriatim to proposed transactions. 3.3. Capacity reservations 3
We suggest that assigning of T A R to power entities entails significant disadvantages and hazards to efficient operation of the market, because of which numerous cumbersome and potentially ineffective rules must be instituted - - many of which are set forth in the NOPR. It would be highly discriminatory for a power entity to reserve transmission capacity without specifying to which load or loads this power is intended. Such a reservation would violate the basic principle of equal access to the network if some loads were obliged apriori to buy power from a given generator only because it reserved and monopolized enough transmission capacity 4. In other words, if, by unconditionally reserving transmission capacity, a power entity prevents certain loads from having access to other possibly cheaper generation, this constitutes a discriminatory reservation through the monopoly of the network, an action that would be against the interest of both loads and generators. 3 In discussing 'reservations,' it is not always clear when or whether the C R T N O P R is dealing in the operations planning time frame (hours to months), or in the system planning time frame (years). We will attempt to discuss 'reservations' in the former, and 'transmission reinforcement' in the latter time frame. In either case, some considerations are the same, but not in all cases. 4 Presumably, moving to market competition is to enable end users to benefit from lowest available cost energy, not to enable suppliers to gain advantages over competitors so they can reduce customer access to transmission.
Effecting a transaction involving the sale/purchase and delivery of power from a power entity to a load entity requires the use of a greater or lesser portion of a transmission network connecting the two parties. Where there are many power entities and many load entities, the potential number of 'paths' between pairs of sellers and buyers becomes huge. If transmission access is sought after agreement on a transaction has been reached, then the agreement may have to be renegotiated or voided if the righls cannot be obtained; if the rights are confirmed prior to an agreement, multiple generators may be seeking rights for the same or related transactions, causing apparent congestion. In either case, the number of studies required could be exorbitant. If, alternatively, transmission access is sought by each interested provider on behalf of the intended receiving load entity, then this is tantamount to assigning the access right to that load entity, except that it involves multiple competing 'nominations' in lieu of one. Under the proposed free market in e,nergy, the 'load' of (i.e. energy drawn from) any generator may be very volatile, in response to changing market conditions, whether viewed from the short term or over a longer term. In order to have enough T A R to serve any potential customers, any given power entity must have rights that are necessarily redundant vis-a-vis those of its competitors. In the course of the functioning of the market, such rights will have to be re-assigned from one generator site to another (unless the network is ridiculously overbuilt to an extent the national economy could not support), and such reassigning will hold potential for game playing by power entities whereby they will seek market advantages over competitors to the extent of curtailing equal access of load entities to the lowest potential market prices for needed power. Both primary and secondary markets will have to be established, regulated, monitored, with increasingly complex rules enforced, penalties defined and imposed, ad nauseam. It is a significant fact, however, that energy required by load sites will remain much more stable than will loads served by generating sites. This is because loads cannot arbitrarily be transferred from one geographical (or to any significant extent, from one electrical) site to another, whereas the generator serving a given load may, and often is, freely 'dispatched' from one generating site to another, perhaps very distant, one. The (local) transmission capacity required to serve a given load site is a known, slowly varying: quantity. The existing transmission grid has been (and any future
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development of the grid must be) designed and built to accommodate the needs of given load sites for energy. Thus, if T A R are viewed vis-a-vis load entities, the need for those rights, in each case, is a relatively known, stable, quantity. The network has been built, and over time has been and should continue to be, reinforced to satisfy those needs. If a load entity wishes to procure the lowest priced energy at any point in time, and if it has been assigned T A R to the transmission capacity that was built into the system to satisfy its requirements, then it will be free to shop among all available power entities (subject to security constraints, to be discussed later), and apply, to any transaction into which it wishes to enter, sufficient capacity rights to effect and complete that transaction. No game playing is involved, no secondary market, no infringement on free access of load entities to cheapest available power except by the physical constraints that dictate secure operation. The discussion thus far has propounded a concept, termed 'load entity transmission access rights,' (LTA) that provides an alternative to that of the CRT NOPR, and that we believe comes much closer to achieving the objectives and meeting the relevant criteria. It is evident, of course, that under severely congested conditions (beyond design parameters), any capacity reservation, even for a transaction between a generator and a load, can be implemented only at the expense of other transactions. This justifies the concept of a proposed transaction. Only after some security-monitoring entity approves a proposed transaction from the perspective of system security, does it become a reserved transaction. In most cases, however, in most parts of the country, approval by the security monitor will be pro forma, obviating the need for much complex realtime analysis.
4. T a r i f f - -
c o m m o n g o o d or m a r k e t basis?
Transmission tariffs necessarily reflect the status that is accorded to the transmission network. Unless its status as a common good is given priority, that status could very well be rendered nugatory by an inappro priate tariff. 4.1. Incentives for transmission system reinforcement and expansion
The CRT N O P R raises an implicit question of the role of transmission grid as a player in a competitive supply/demand market process. As implied by the interdependence of tariffs and network status, different incentives will result from the network's being treated as a regulated common good monopoly, or a regulated
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market based monopoly. The former status, with its attendant obligation to provide transmission service to all connected loads, would seem necessarily to require the traditional regulated rate of return on investment to ensure ongoing provision of adequate facilities. The latter status suggests market incentives that will lead to minimum cost economically efficient expansion within regulated capped rates, but would necessarily subordinate an 'obligation to provide access' to an 'ability to pay' (which would be counter to the motivations for establishment of the Rural Electrification Administration in 1936) 5. Unfortunately, in addressing this issue, we are faced, prior to any technical issues, with the imponderable ethical issue of fairness, of an obligation to serve versus a commitment to market efficiency. This issue will be resolved ultimately in a political context. Let us consider the implications of treating transmission as a common good. For traditional regulated utilities under an obligation to serve, regulated recovery of costs to meet revenue requirements (rate-of-return on investment) have proven effective in assuring robust reliable systems, to the extent that some have argued at times that such systems have been 'gold plated.' In view of the uncertainties that await the electric energy industry in the restructured future, as well as the requirements for open access to competing power entities, it may well be that such an incentive struclure may be necessary to ensure adequate transmission capacity. The LTA paradigm could accommodate a variety of tariff structures. Perhaps the simplest approach, and most consistent with traditional practice, fbllows from continued recognition of the transmission entity, per se, as still being a common good, as well as a regulated natural monopoly.
The approach to transmission access rights in this article implies that the load entities will acquire those rights by virtue of the transmission network having been designed to provide access adequate to their needs, and, a corollary, that they should pay for that access according to the traditional regulated utility formula based cost-based revenue requirements. Access rights of a load entity to the local transmission network would be provided in proportion to the coincident peak load of that entity (within its region). For native load entities, the (regulated) transmission tariff would contain a fixed and a variable (load dependent) component. The fixed component would be calculated (as have been traditional regulated utility rates) to 5 It is relevant to note that deregulation of the airline and railroad industries has resulted in withdrawal of air and rail service from widespread rural areas of the US
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recover all fixed costs plus an approved rate of return on investment (the revenue requirement) based on the coincident peak load demand of the connected load portion of all entities serving loads on that transmission system. The additional variable portion of the fee would then include any network related ancillary service charges, including, for instance, transmission loss charges, a charge for other network related expenses such as purchased reactive energy, purchased power to cover transmission losses, etc. It would be possible to augment this structure by a congestion related component that would relieve congestion via appropriate price signals. It is important to note that, in this traditional approach, as a regulated monopoly with tariffs calculated to provide a recognized rate-of-return on investment, the transmission entity would have the same incentive as led the traditional industry to provide capital intensive, robust, reliable systems. Transmission expansion under any scenario requires forecasting-based planning. The C R T N O P R alludes in several places to considerations of planning system reinforcement and expansion, and the advantages of the CRT framework in this connection. For instance, it states that "the transmission provider knows only the customers' historical loads, not their future loads... The transmission provider may not have any good way to forecast the increase or decrease in the loads of customers it has no obligation to serve" [[2], p. 81]. This means that the utility who is the transmission provider can forecast the growth of those portions of its connected load who still purchase their energy from it, but they cannot forecast the growth of loads connected to its system that are purchasing their energy from other power entities. But this is beside the point. So far as its 'native load' (in this restricted sense) is concerned, that load is no longer captive, as in the past, and presumably any or all of it may choose, tomorrow-, to become the load of some other provider. This observation also pertains, pari passu, to the other power entities that are involved their future load is no more predictable than the transmission providers. -
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What is still true, however, as true as in the past, is that the connected load on the transmission provider's system is still as predictable, though no more predictable, than it has been in the past, and the transmission entity should still be as able to forecast that load for the purposes of reinforcing its network as its utility predecessor was in the past. The CRT N O P R recognizes in one or more places that there may be problems in arriving at an optimal
expansion of the system through basing it on the forecast needs of relevant power entities. For instance, it states that "an argument can be made that the CRT approach may lead to an understatement of A T C " [[2], p. 9]. This is equivalent to saying it could lead to an over statement of the need for additional capacity, and is quite true, since competing power entities would be forecasting redundant needs, each hoping to attract some of its competitors' customers. Under the LTA paradigm proposed in this response, however, this is not the case. Under this paradigm, as already explained, the transmission entity would forecast the need for system reinforcement to meet the needs of its connected load, which is equivalent to what utilities have done in the past. What will be more difficult to predict will be the location of future generation, since this will now be decided by the influence of market forces on a variety of individual third party, existing or future, power entities. However, it will be to the advantage of power entities to keep the transmission provider fully aware of their future plans, so that the information available to the transmission provider will be nearly as good is it was in the past to the predecessor utility.
4.2. Wheeling and parallel flows Access to off-system (outside the host transmission system) capacity requires different treatment. The argument thus far has been that load entities have already paid for much of of the transmission facilities built to serve their demand (i.e. what's already been depreciated), and that those load entities should continue to pay for such facilities in the same manner, i.e. via a regulatory-approved required revenue based tariff. Use of the local grid by 'foreign' generation presumably would be in order to serve local load. Thus there is no essential difference in use of the network. However, for wheeling, the story is different. Since capital investment in the network would be recovered under the native load tariff, wheeling access granted to off-system entities, to the extent that they did not infringe on access requirements of native loads, could be granted on an implicitly reciprocal basis, with charges confined to reimbursement for necessary ancillary services including losses proportional to the imposed flows. If multiple, conflicting requests were involved, they could be granted on the basis of some form of a variable, transaction related charge, payable to the network(s) involved. (In the interests of effectiveness, these charges should probably be passed through some central clearing house, perhaps a role of the local transmission entity.) Since these TAR would be subsidiary to the native rights of load entities within each system, they would be acquired via the market at market clearing price.
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The handling of parallel flows is, as well known, a matter of much debate. This is not the occasion on which to muddy the waters, as it is not central to the present discussion. However, as an aside, in view of the complexity of all proposed solutions for providing even approximately correct distribution of costs, consideration should be given to appropriate zoned fares. If the overall network were divided into appropriate electrical zones, it would be fairly straightforward ex ante to determine by load flow what fraction of a transaction would flow across which zones, and ex post to apportion wheeling charges proportionately. Since this would be done considering only the transaction involved, in the absence of other flows, it would be approximate, but should be a fair attribution of costs over the long run for large numbers of transactions. As the system evolves from here on out, under open access, with new flow patterns emerging that require reinforcement of the grid beyond what is required to serve local loads, then such reinforcement could and should be provided by the transmission entities under a different tariff that would recognize and compensate those entities for the risk that would be involved. An attractive mechanism for this purpose would be a peak load pricing formula [6]. Such reinforcements should be excluded from the rate base used for determining loadserving-entity base tariffs, and should be paid for under the peak-load pricing rates applied to wheeling contracts, on a case by case basis. Such practice would make very clear when (and over what distances) wheeling is really economical. Also to be considered is the possibility that evolution of the system may be such as to actually reduce loading of the network if the technology and economics are such as to lead to construction of a great deal of low cost, dispersed generation sited close to loads! This would be a reversion to earlier patterns of system use. In the 1950's, it was not uncommon for bulk power systems to be lightly loaded, since they served only to provide a reserve for emergency capacity transfers. In the case of congestion, zones who suffer from the effects of parasitic flows should be reimbursed by the transactions causing those flows. Zoned tariffs could also serve to utilize market forces to relieve congestion. Escalation of the variable portion of the tariff within congested zones as loads increased would encourage modification of transactions to alleviate congestion, if the use of those tariffs were restricted to such use [7].
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requested ('nominated') access. However, in order to discuss capacity rights, it is essential to account explicitly for the various network limitations defining system security, namely, transmission flow limits, N.-1 security, voltage and reactive power bounds and stability. System security must be an integral part of the definition of transmission capacity and not a secondary service. It should be emphasized that the set of security limits of a power network is what defines its transmission capacity. Security is a complex multi-dimensional property of power networks, and hence, so is transmission capacity. Transmission capacity cannot and should not be treated as a one-dimensional quantity, and certainly not as a linear property to which superposition applies. Transmission capacity depends on: (i) the values of numerous network variables and parameters; (ii) which power transaction is being considered; and (iii) the levels of every other network transaction taking place simultaneously. Some transactions may stress network security only slightly, while others will quickly lead to the saturation of certain lines or to other security limits. Therefore, available transmission capacity will vary drastically from one transaction to another. The physical factors that characterize the security region for the network (i.e. the set of all possible operating points that do not violate any security constraint) are inherent in the network topology and the characteristics and condition of its components, and cannot be changed by operating practices, although their becoming active may be circumvented under some circumstances, to a certain limited extent and at a cost. The necessity of maintaining secure operation of the system vis-a-vis potential disturbances is responsible for much of the difficulty involved in evaluating and allowing or disallowing potential transactions. This is not the time to write a manual on power system security assessment. Suffice it to say that N-1 security (the ability of the system to ride through loss of any one major component without violating stated security constraints) and its derivatives require voluminous dynamic as well as steady state analyses of system responses in its current or in many projected operating states, to any one or selected combinations of 'credible' disturbances. On a large system, the dimensionality of this task can be overwhelming. 5.1. Security constraints
5. Secure system operation The concept of transmission capacity presented in the N O P R does not explicitly refer to the necessity of satisfying power system security, although it is implicit in the requirement for approval of ('reserving') any
If security assessment is to be carried on effectively within a restructured industry, it is not only prudent, but necessary to build on present adequate (admittedly not ideal) practice rather than prescribing some new, unproven solution to a problem that is becoming more,
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rather than less complex 6. Due to the complexity and overwhelming computational effort involved in analyzing system security in real time, utilities have been forced to develop approximate (and therefore conservative) methods for real-time security assessment.
burdensome, closer to proven accepted power system practice, and hence more feasible and to be preferred over the generator-referenced alternative.
It will be highly desirable, initially, to make new practice as compatible as possible with present proven practice.
Much of the foregoing discussion has focused on the inherent rights of load entities to access local transmission capacity. It is recognized, however, that increasingly now for some time, energy transactions span greater distances, crossing one or more transmission entity boundaries in the process. (For the purposes of this present discussion, we are assuming that transmission entity boundaries coincide with existing control area boundaries.) Thus the concept of transmission access rights (TAR) transcends that of load entities to their local networks.
For instance, current practice with regard to security constraints often is based on sets of limiting flows across critical boundaries, and dispatch and interchange transactions are permissible so long as these constraints are not violated. Under current practice, these constraints are conservative, but necessarily so because updating the numerous calculations that are involved is not possible in real time. If this practical necessity of current practice is acknowledged (as it must be), then new procedures should build on this practice as far as possible. Such practices can then be extended to accept less conservative, more up-to-the-moment constraints as their calculation becomes feasible. For any generator (exporter) to put together and acquire TARs for transactions to sell its available energy, it would have to calculate, or have calculated, a very large number of case studies showing that import limits of all potential buyers will not be violated in the face of all existing or possible transactions (possibly involving many of the same potential buyers) desired to be entered into by competitors. For this it would be dependent on the network security monitor. Providing such monitoring for all power entities for all desired transactions (sales) would be so formidable as to approach infeasibility in real time unless it is done very conservatively. A different constraint is likely to apply to each proposed transaction, and to be a volatile function of all other simultaneous transactions. For any load entity (importer) to know the security constraints affecting any proposed purchase from any potential supplier, it can be calculated with a good degree of (conservative) accuracy on the basis of precalculated, periodically updated interface flow constraints provided by the network security monitor. A given constraint is likely to apply to a large set of possible transactions of potential interest, and to be affected by another large set of possible transactions collectively rather than individually. Thus, this load-referenced procedure is prima facie more direct, less computationally 6A leading industry expert [5J has recently pointed out the difficulties that have bedeviled the EMS (energy management system) industry in supplying state of the art software adequate to the needs of the current state of the industry.
5.2. Wheeling, parallel flows, and congestion
The use of neighboring, and more distant, networks in order to implement a transaction will require access to transmission facilities to which the load entities (as well as the generating entities) involved have no inherent rights. Two major questions immediately arise in these situations: that of contract or other paths that are involved when importing power from off-system sites, and that of the parasitic parallel (or loop) flows that affect portions of the larger network that are not directly on the contract path.
5.2. I. Wheeling Again, in this context, we need to consider: (i) who should be eligible, or responsible for acquiring TAR in such cases; and (ii) how should such :rights be paid for? It has already been stipulated that, in these cases, the load entities as well as the generating entities involved have no inherent rights. However, in recognition of the fact that it will always be the end user who pays the bill, as well as in the interests of uniformity, it is suggested that in this case also (i.e. the case of acquisition of off-(local)-system transmission rights for effecting a given transaction), it should be the buying (load) entity who acquires those rights. This eliminates any chance of unproductive overhead charges being added to the transaction, it reduces if not eliminates the need to consider multiple TAR during the negotiation process (since load entities will be aware of the critical interfaces at which they still have some margin, and will shop amongst potential suppliers with those interfaces in mind), and will eliminate the need, which has been discussed earlier, for multiple potential suppliers to vie for transmission capacity needed to effect the proposed transactions, and obviate possibilities for gaming on the part of power entities to gain competitive advantages vis-a-vis load entities.
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5.2.2. Parallel flows If T A R are considered in terms of flows across critical interfaces as defined by before the fact load flow analysis, then the problem of treating parasitic parallel flows becomes that of the treatment of congestion imposed on, and of compensation for, all the transmission entities whose networks are affected by a given transaction.
5.2.3. Congestion Congestion arises when the network is loaded close to its capacity, and the (conservative) security constraints on flows across critical interfaces become inadequate criteria. In such cases, it becomes necessary for the transmission security monitor (who in some proposals will be an ISO) to treat proposed transactions on a one-by-one basis. Three cases should be considered: (i) when the congestion is due to generally heavy loads on the system; (ii) when the congestion is caused by requests for wheeling through a given system; and (iii) when the congestion is caused by parasitic parallel flows due to wheeling on adjacent systems. In each of these cases, it will be necessary to disallow or impose modifications on proposed transactions, but the criteria will be different in each case. In the first case, general congestion due to high loads, it may or may not be the case that native load entities will be exceeding their coincident peak load requirements. In either case, the network security monitor will have to: (i) treat proposed transactions according to the principle that the native load entities are entitled to use of the system proportionate to their coincident peak load requirements; and (ii) modify transactions, on a case-by-case basis, in such a way as to maintain this proportionality. The effect may be that one or more load entities will be forced to forego access to the lowest cost generation. In principle, the trading of reserved transmission capacity among transactions is feasible, however, this is severely complicated by the fact that reserved transmission capacity is not additive [[2], pp. 8, 9] but rather highly non-linear 7. Trading of reserved transactions could take place but would be highly dependent on relative MW levels and market values of each transaction and it would have to be approved by the security monitor to ensure that security was satisfied. In the second case, when the congestion is caused by requests for wheeling through a given system, it will be necessary to recognize the priority of native loads to 7 Thus, under congestion, cases can arise where the reduction of a given reserved transaction by 1 MW permits another transaction to be increased by only 0.5 MW so that, in order to meet the load, a third or perhaps more transactions would have to be modified.
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access to their local transmission system. It would be inequitable to force load shedding, or even otherwise unnecessary increases in energy costs, on local loads (who, through their tariffs, are paying for the local transmission capacity) for the benefit of foreign users. In the third case, when the congestion is caused by existing parasitic parallel flows due to wheeling on adjacent systems, to the extent that such loading precludes access of native load to low cost energy, they should be reimbursed for their higher costs; by parties causing the parasitic flows.
6. Summary: a new paradigm
The network was designed and built to provide unbottled generation access and adequate local service simultaneously to all load centers under forecast normal and recognized emergency conditions. Needs of loads for transmission access are known and stable, and are not volatile vis-a-vis individual transactions. To the extent that they are compatible with the requirements of other load centers, each load's needs may be satisfied within network constraints. For any load to seek access outside these constraints would violate the rights of other loads to equal access. The CRT N O P R [[2], p. 8] suggests that putting all users (by which they mean power entities) on a reservation basis appears to be compatible with the new OASIS and the requirement that market ]participants know how much transmission is available for their use. We suggest that recognizing that load entities have an inherent access right to the transmission capacity that was designed and built to ensure satisfaction of their load requirements, making known to all market participants what are the current security constraints that dictate how much energy may be imported across given interfaces into that entity's region, then the market participants do know how much transmission is available for their use. The relevant market participants in this case are the load entities, since they a:re free, and are entitled, to import for their load energy from the lowest cost (or other preferred) power entity subject only to non-violation of stated and published security constraints. Thus, load entities always have 'reserved' that portion of the network capacity serving their region that is required to satisfy their requirements under all but extreme emergency conditions. The C R T N O P R suggests that the C R T policy will satisfy a variety of objectives and provide numerous advantages over alternatives. We believe we have shown that there are numerous significant economic and operational advantages to develop a tariff based: (i) on transmission entities who have no incentive or opportunity for viewing or treating any source of power connected to their network any differently from any
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other source of power on or off their network; and (ii) on assigning T A R to load entities, not to power entities. The N O P R states ([2], p. 6) that, "in adopting the Final Rule tariff in the Open Access Final Rule, our purpose was to remedy undue discrimination in the provision of interstate transmission service, not to reform traditional tariff design." In this and other statements throughout, the emphasis is on remedying (or avoiding) undue discrimination by transmission providers who are in fact generating utilities against other power entities who are not transmission providers. We suggest that this is insufficient to meet the objective of providing free play of the market among all participants, not just power entities. The C R T N O P R [[2], p. 14] suggests that " I t would appear that transmission service would be fully unbundled from generation service under a C R T because the generation and transmission products are reserved and used independently." We suggest, rather, that by assigning T A R to power entities, regardless of how level the playing field (or market) might be by means of which those rights are sought (nominated) and obtained (reserved), generation and transmission are de facto rebundled vis a vis the end user, and that the equal access rights of the demand side of the market (load, or load-serving, entities) is subject to violation. In general, once a power entity has obtained T A R , to some extent the access of other power entities to equivalent rights is limited. This is not necessarily objectionable so far as equity among power entities is concerned, since the rights were obtained by fair competition. However, it is very objectionable with regard to load entities because it restricts their equal access to all potential power suppliers, and to that extent the market power provided by bundled generation and transmission (G and T) vis-a-vis load entities re-emerges. Assigning of T A R to generators would inevitably lead to the proliferation of byzantine rules, regulations, oversight, and penalties in the attempt to ensure a level playing field of equal access for all parties. This is because generators would have implicit motivation/incentive to game the system in such way as to maximize their own access and minimize their competitor's access. The end result would seem to be to develop a 'seller's market,' wherein de facto recombination of generators with transmission facilities, albeit under new
competitive realignment of players, would reflect collectively, in some way, the status quo ante of the industry, with room for jockeying (and game playing to obtain advantages) a m o n g the generators. Load entities would have no such incentives, being only concerned with assured access to sufficient transmission capacity to meet their own needs. Thus, assignment of T A R to load serving entities would even the playing field between buyers and sellers, tending if anything toward a buyer's market, with advantages toward the end user. In comparing load (LTA) versus generator (CRT) transmission access rights, we suggest that, under load access: load is assigned T A R to match its (coincident peak) requirement; there is no need for a secondary market; transmission stranded cos~Ls are eliminated; non-discrimination is extended to encompass load as well as power entities; flexible shifting of generation is inherent; economic efficiency in network reinforcement is inherent, since necessary expansion is rewarded without any incentive for overexpansion. Conversely, under generator access: discrimination vis-a-vis load entities is inherent; power entities are given advantage over potential customers; there is an inherent tendency toward inefficient overbuilding of the network, since competing generating entities may attempt to nail down (redundant) capacity adequate to serve customers they hope to get!
References
[1] Federal Energy Regulatory Commission: Promoting wholesale competition through open access non-discriminatory transmission services by public utilities, Order No. 888, Final Rule 24, April 1996 (Docket Nos. RM95-8-000 and RM94-7-001). [2] Federal Energy Regulatory Commission: Capacity reservation open access transmission tariffs: notice of proposed rulemaking, 24 April 1996 (Docket No. RM96-11-000). [3] L.H. Fink, Ancillary transmission services, Electr. J. 9 (5) (19961 18-25. [4] R.D. Tabors, Lessons for the UK and Norway, lEEE Spectrum 33 (8) (1996) 45- 49. [5] R.D. Masiello, It's put up or shut up for grid controls, IEEE Spectrum 33 (8) (1996) 50. [6] B. Lecinq, M.D. Ilic, Peak-load pricing for electric power transmission. J. Regul. Econ. (submitted). [7] M.D. Ilic, F. Graves, Optimal use of ancillary generation under open access and its possible implementalion. TR 95-006, Mass. Inst. of Technol. Lab. for Electromagnetic and Electronic Systems. August 1995.