AFTER MUCH DISCUSSION AND INNOVATION, CALIFORNIA is scheduled to launch its new electricity market (known as WEPEX) on Jan. 1, 1998, and we have a chance to revisit the issues. In the earlier round of this conversation, now three years past, I argued that the debate contrasting pool and bilateral models for a restructured electricity market was missing the point. %n1%n
I had thought the pool versus bilateral debate would be over by now; having both would have solved it. Yet the dispute lingers on in the somewhat schizophrenic provisions of the WEPEX proposals that solicit bids from the market participants, but then impose unnecessary constraints on the system operator's use of the bid information and obstruct operation of the pool with its least-cost economic dispatch. To be sure, there is much to praise about the WEPEX innovations. We all would benefit from a success in this major restructuring effort. If WEPEX is a take-it-or-leave-it proposition, taking it would be better. However, the public would prove well-served if the WEPEX independent system operator excised some of the most contorted logic it inherited and simplified the rules to support both pool and bilateral transactions.
Just Say "Yes"
The point made three years ago and still applicable today, is that the electricity market cannot operate at all - much less efficiently - without a system operator. Since we cannot rely solely on decentralized, bilateral transactions to match supply and demand, the real issue is reduced to establishing the role and responsibilities of the system operator in performing its functions in support of a competitive generation market. Recognizing that the system operator must offer a balancing and dispatch service, I summarized key matters in dispute then with three questions that are still relevant:
(1) Should the system operator be allowed to offer an economic dispatch service for some plants? (2) Should generators and customers be allowed to participate in the economic dispatch offered by the system operator? (3) Should the system operator apply marginal cost prices for power provided through the dispatch?
The recommended response was to "just say yes" to all three questions. In this case, the system operator would provide the necessary balancing as an efficient dispatch open to anyone who wished to participate. Pricing would apply the marginal cost principles of a competitive market based on the voluntary bids of the participants. And these same prices would apply to all uses of the transmission grid under a comparable, open-access transmission tariff. Bilateral contracts would be fully available. With this voluntary approach, the models merge, or differ only in accounting practices. By now the full details of such a package can be found in the filings of the "supporting companies" in the Pennsylvania-New Jersey-Maryland Interconnection or the New York Power Pool, both having elected to "just say yes."
The Federal Energy Regulatory Commission has declared itself in support of the same approach in its earlier "guidance" to WEPEX:
¼the companies have clarified that, under their proposal, the ISO can accept voluntary information from all generators and loads in order to relieve transmission congestion and provide ancillary services.
We accept the companies' clarification. In addition, we will require that the ISO be allowed to use all information it receives in order to develop a least-cost schedule (for energy and ancillary service) in performance of its responsibilities to efficiently manage congestion and satisfy its control area responsibilities. %n2%n
With this clear admonition last year from the FERC, the ISO, the PX and the three major electric utilities returned to the Commission on Aug. 15, 1997, when they submitted Phase II of their proposed restructuring of the California electric market. They won conditional FERC approval on Oct. 30. %n3%n
The Cost of Saying "No"
Unfortunately, however, WEPEX has not said "yes." Rather, the WEPEX response - now accepted by the FERC - is better characterized as "whenever it makes a difference, the answer is no." There are restrictions on least-cost dispatch, but the WEPEX sponsors contend that if the market will solve the problem, economic dispatch is not necessary; this is the old "bilateral-only" argument reborn. But if the market cannot solve the problem, then the WEPEX restrictions will apply to prevent the system operator from clearing the market. Although it was still a moving target as the deadline approached, even after the latest round of conditional FERC approvals on Oct. 30, the WEPEX proposal does not conform to the initial FERC requirement. These restrictions on economic or least-cost dispatch are not a surprise. %n4%n What is surprising is that the FERC has apparently acquiesced to the contorted logic and shifted the burden of proof against the provision of economic dispatch.
The contortion in the logic is most evident when we look at the WEPEX rules for real-time dispatch and balancing. For brevity, we pass over the day-ahead forward market where the analysis of the restrictions on economic dispatch is more contentious. But in the real-time market, where the system operator is responding to changing conditions, we are by definition in the period after the interval where participants in the market can do anything on their own to achieve equilibrium or an efficient outcome. (See sidebar, "Banking on Bids" and comment by FERC on the ISO's "unique position" to facilitate trades.)
In real time, only the system operator can minimize cost and achieve equilibrium, and in WEPEX this is forbidden when the system is not naturally in equilibrium. Restrictions are built in expressly to prevent the least-cost outcome of equilibrium in the energy market. %n5%n The system operator is required to ignore certain bids for changes in real-time balances. Instead, the system operator will deliberately pick a more expensive dispatch at a time when the market cannot possibly undo the damage. Inevitably, these restrictions can create anomalies like some market participants paying for their imbalances at prices greater than they had offered to change these same imbalances if only the system operator had considered their bids.
In response to these restrictions, the FERC imposed several reporting requirements on the WEPEX system operator in an attempt to test the proposition that the restrictions on least-cost dispatch do not matter. %n6%n Under the circumstances, such reporting is good and necessary. Perhaps this will be sufficient, but there are at least two reasons not to be sanguine. The first concern is that the focus is on the estimated total cost of the dispatch restrictions. This criterion is incomplete. The real advantage of the system operator providing an economic dispatch service is to deal with complicated network interactions and make it easier for market participants to engage in transactions, especially small players who would find it hard otherwise to obtain balancing support. Are we confident that the balanced schedules and supplemental bids offered without economic dispatch are the same as those that would result with economic dispatch? This is an implicit assumption of the FERC reporting requirement. Or would behavior be different, as the proponents of the restrictions seem to anticipate? No good reason exists to impose the restrictions. But there are plenty of reasons to remove the restrictions, which only make the system operator's job more difficult.
The second concern is that the procedures for calculating the costs of the restrictions are incomplete and are being developed within the convoluted zonal framework that embodies the latest vision of the contract path for transmission. The zonal framework presents its own incentive problems, the pursuit of which goes beyond the scope of the present comment. Suffice it to say that the pervasive WEPEX reference to the "two" sides of a transmission interface constraint between zones is all an elaborate fiction. If there are looped connections in the transmission network, then the constrained lines do not have just two sides. Every location will have a different effect on the constraints. Hence, every location will have a different marginal cost that can be determined only by using the distribution factors of a full contingency constrained power flow model, an unpleasant reality from which WEPEX is not exempt. Experience has shown that it is quite easy to obfuscate these real effects and obscure the degree of cost shifting. Given the California precedent of "Inactive Zones" designed to spread the costs around, getting agreement on this impact analysis may not be so easy.
We could eliminate these problems by giving the WEPEX system operator the simple charge to follow the original FERC guidance and using standard procedures for economic dispatch of energy and ancillary services. Then we could turn to other neglected topics, like transmission congestion contracts, that have been pushed aside by the distracting debate. It turns out that it is a lot harder to say no to the three questions; the market structure would be better and simpler if the WEPEX system operator could just say yes.
William W. Hogan is the Thornton Bradshaw Professor of Public Policy and Management, John F. Kennedy School of Government, Harvard University, and senior advisor of Putnam, Hayes & Bartlett Inc. This presentation draws on work for the Harvard Electricity Policy Group and the Harvard-Japan Project on Energy and the Environment. Many individuals provided helpful comments. The author has consulted on electric market reform and transmission issues for British National Grid Co., General Public Utilities Corp. (working with the supporting companies of the PJM proposal), Duquesne Light Co., Electricity Corporation of New Zealand, National Independent Energy Producers, New York Power Pool, New York Utilities Collaborative, Niagara Mohawk Corp., San Diego Gas & Electric Corp., Trans Power of New Zealand, and Wisconsin Electric Power Co. The views presented here are not necessarily attributable to any of those mentioned. Any remaining errors are solely the responsibility of the author.
1 William W. Hogan, "To Pool or Not To Pool: A Distracting Debate," Public Utilities Fortnightly, Jan. 1, 1995, p. 24.
2 FERC Order, Pacific Gas & Elec. Co., San Diego Gas & Elec. Co. and So. Calif. Edison Co., Docket Nos. ec96-19-000, et al., Nov. 26, 1996, p. 36, 77 FERC ¶ 61,204, at p. 61,810.
3 FERC Order, Pacific Gas & Elec Co., San Diego Gas & Elec. Co., and So. Calif. Edison Co., Docket Nos. ec96-19-001, et al., Oct. 30, 1997.
4 Steve Stoft, "California's ISO: Why Not Clear the Market?" The Electricity Journal, Vol. 9, No. 10, Dec. 1996.
5 California Independent System Operator, "Dispatch Protocol," Oct. 31, 1997, p. 24-25. See especially paragraphs (d) and (h), which marks the tip of an iceberg that has not been fully formed.
6 See FERC Order, note 3, supra, especially page 97, under "2. Balanced Schedules and Usage Charge."
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