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«Abstract Transmission pricing and congestion management are the key elements of a competitive electricity market based on direct access. They have ...»

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Transmission Pricing and Congestion Management:

Efficiency, Simplicity and Open Access

Shmuel S. Oren

University of California at Berkeley

Berkeley, CA 94720

TL. (510) 642-1836 FAX (510) 642-1403 Email OREN@IEOR.Berkeley.edu

Abstract

Transmission pricing and congestion management are the key elements of a competitive electricity

market based on direct access. They have also been the focus of much of the debate concerning alternative

approaches to the market design and the implementation of a common carrier electricity system. This paper focuses on the tradeoffs between simplicity and economic efficiency in meeting the objectives of a transmission pricing and congestion management scheme. I contrast two extreme approaches: the postage stamp approach vs. nodal pricing. The paper questions the wisdom of the nodal pricing paradigm on the grounds of its rigidity and complexity. I argue that the theoretical efficiency properties of nodal pricing are unrealistic and do not justify the implementation drawbacks of the approach. The paper explains the underlying principles of least cost congestion relief, adopted in California that treat congestion relief as an ancillary service and enables the ISO to relieve congestion efficiently with minimal intervention in the energy market. I also discuss zonal aggregation and describe a new zonal priority network access pricing that complements interzonal congestion pricing by offering a market mechanism to guide intrazonal congestion management and provide economic signals for location of generation resources.

Introduction:

There is general agreement among academics practitioners and policy makers that direct access to the transmission grid is the essential centerpiece for a competitive electricity market. Order 888 and Order 889 of the Federal Regulatory Energy Commission (FERC) reflect the role of direct access as the foundation for the electric power industry restructuring. These orders provide guidelines for nondiscriminatory transmission pricing and mandate timely disclosure of available transmission capacity but do not prescribe a particular approach to the institution of direct access. However, the prevailing restructuring paradigm being adopted in many states in the US has two key features: functional unbundling of generation transmission and distribution and the transfer of control over the transmission system to an Independent System Operator (ISO). The establishment of the ISO as a key institution in the emerging competitive electricity markets is based on the consensus that the physical characteristics of electricity impose requirements for real time central coordination in order to assure reliable service. However, the extent of centralized control and “market management” that is needed to assure system reliability and that is desirable from a social efficiency perspective has been a subject of public debate. That debate has polarized the restructuring approaches adopted so far on the east and west coasts of the US. This divergence manifests itself in the transmission pricing and congestion management protocols the centerpieces of a direct access system and two of the key functions of the ISO.

In an open access, competitive electricity system a transmission pricing scheme should fulfill several

functions and meet various criteria:

S Generate revenues to compensate the owners of transmission assets S Produce economic signals for efficient rationing of scarce transmission resources S Produce economic signals for efficient investment in transmission and for efficient location of new generation capacity and loads S Be simple to implement, transparent and conducive to energy trading.

Like most lists of desiderata, the above requirements can only be met partially by any practical transmission-pricing scheme, which requires some tradeoffs and compromises. One of the basic tradeoffs in this context is between simplicity and short-term efficiency. The questions that one must address in

making this tradeoff are:

S How precise need the short-term economic signals be to move the system toward long-term efficiency?

S What is the economic cost of a simpler and less accurate pricing scheme?

S What is the correct level of precision in short term price signals given the approximations in the system models, the formulation of objectives and the available computation technology?

S How we compare the economic value of an accurate ex-post price signal to an approximate ex-ante price signal?

Another important tradeoff concerns the desired level of decentralization. The two basic paradigms for optimal resource allocation are the central planning approach versus the decentralized "invisible hand" approach. The equivalence of the results in an idealized theoretical setting has enabled economists to simulate market outcomes by using optimization models. Indeed market simulation is the proper use of optimization technology in a competitive market setting. The endlessly debated philosophical question is to what extent should a market simulation model be used to manage the market. This debate dates back to the 1920's when the concept of planned economies was first proposed. Using a market simulation model to set prices as advocated by some in the electricity restructuring debate is somewhat analogous to using statistical poling to determine (rather than just forecast) election results. The physical characteristics of electricity and the network aspects of electricity transmission justify a certain degree of central coordination in order to maintain system reliability. However, the extent to which central intervention based on optimization models should be used to insure short-term economic efficiency is a debatable policy decision with direct consequences for transmission pricing and congestion management protocols. The argument for a centralized market management approach is that given the need for central coordination (for reliability considerations) it would be foolish not to take the extra step and optimize resource use so as to maximize short term efficiency. The counter argument is that, multiperiod efficiency need not collapse to the sum of single period efficiencies. Massive integration of systems on cost-based efficiency grounds can come at a loss of gains from competition and innovation born of profits. Decentralization and minimal central intervention in the market will promote long term efficiency by facilitating interaction between buyers and seller, customer choice, intermediation and technological innovation. The basic question is then does the long term potential gain justify the short term losses caused by the response lags and inefficiencies of a decentralized system.





The differences among the various proposed schemes for definition of transmission rights, transmission

pricing and congestion management can be categorized along several dimensions as follows:

S Physical vs. financial transmission rights S Link based vs. node based (point to point) definition of transmission rights S Access based pricing vs. usage based pricing S Locational differentiation in tariffs: nodes, zones or uniform prices S Ex-ante vs. ex-post pricing S Bundling of transmission service and energy vs. treating energy and transmission service as separate commodities S Congestion management through efficient generation dispatch vs. efficient congestion relief.

It is beyond the scope of this paper to provide a comprehensive survey of all the proposed approaches and even if we tried we would probably miss some. Instead we will focus on two basic ideas related to the simplification and decentralization of decision making in the deregulated electric power industry. First I will explain how the California congestion management approach has been able to separate the energy market from the transmission market by, effectively, treating congestion relief as an ancillary service. Next I will discuss the issue of zonal aggregation and describe a new priority zonal network access pricing approach that may be viewed as an extension of the familiar postage stamp approach. The proposed scheme enables efficient intrazonal congestion management based on a relatively simple ex-ante transmission tariff. In order to put these ideas in context I will first contrast the two extreme approaches on the simplicity vs. efficiency tradeoffs.

Simplicity vs. Efficiency: Is Nodal Pricing Worth the Trouble?

Two opposite extremes in terms of the tradeoff between short-term efficiency and simplicity in transmission pricing are the nodal pricing approach and the postage stamp approach. In the latter transmission pricing takes the form of a fixed ex-ante charge per MWh for transmission service between any two points in the grid. The simplicity and certainty of this approach is compelling from the point of view of energy trading over the grid. However, it has been argued that the lack of locational differentiation results in no economic signals to investors and users for efficient location of new load (e.g. production facilities) and for the location of new generation and transmission lines. Furthermore, postage stamp transmission pricing does not elicit economic signals from customers that could be use to manage congestion efficiently. There is, however, little evidence as to the magnitude of the efficiency losses resulting from the lack of correct economic signals and the debate is raging with regard to how precise these signals need be to recapture most of these losses.

Motivated by short-run efficiency considerations, the nodal pricing approach advocated by Hogan [1992] manages congestion and sets transmission prices through a centralized energy market based on economic dispatch. The basic idea of the nodal pricing approach is to organize the market as a pool in which generators (and ideally loads) submit hourly bids for node specific injection and withdrawals of power to an Independent System Operator (ISO) with full coordination and price setting authority. The ISO minimizes the total system's gain from trade (demand bids less supply bids) subject to transmission and reliability constraints. The price at each node is then set to the incremental bid price of the most expansive unit generated or consumed at the that node. These nodal prices become the hourly prices charged to loads and paid to generators at the respective nodes. When there is no congestion all nodal prices are in theory identical. However, even congestion on a single link could result in a different price at every node in the system (in the WSCC there are around 2500 such nodes).

Proponents of the nodal pricing approach claim that bilateral transactions can be readily accommodated within this framework. A physical bilateral transaction can be scheduled as if the injection submitted a zero bid and the load submitted an infinite bid. Such a transaction is then subject to an ex-post transmission charge that equal the opportunity cost of the transaction, i.e., the cost difference of selling the power to the pool at the injection node price and buying it back at the withdrawal node price. Thus, the transmission charge between any pair of nodes is set ex-post to the nodal price difference between he nodes. The cost off transmission, therefore, varies between each pair of locations and is only known to energy traders after the fact. Bilateral traders that wish to protect themselves against transmission price risk among two specific locations can do so in too ways. They can acquire transmission congestion contracts (TCCs) between the two locations. These are financial instruments underwritten by the ISO that entitles or (obligates) their holder to a payment that equals the nodal price difference between the nodes. Such a financial contract would enable a trader to fully hedge the transmission price risk between two nodes. Unfortunately, with prices being different at each node and the large number of different TCCs needed to enable full hedging for each possible bilateral transaction (a 3000 node system would require about 4.5 million of different TCCs) it is unlikely that a market for TCCs could achieve sufficient liquidity to make TCC pricing efficient. Without a liquid TCC market the value of these instruments as risk management tools for energy traders is questionable.

Bilateral traders can also manage transmission price risk by actively participating in congestion relief.

The nodal pricing paradigm (as implemented for instance in the PJM pool) restricts such participation to incremental and decremental bids that can be readily interpreted within the framework of the central pool economic dispatch protocol. Specifically, a trader may submit incremental and decremental (inc/dec) bids that would allow the ISO to modify its injection as if it was a pool bidder. With demand side bidding it would also be possible to have inc/dec bids on the load side. Such inc/dec bids, however, allow the ISO to displace the bilateral generator by cheaper generation, for efficiency reasons, even if there is no congestion.



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