Flowgates, contingency-constrained dispatch, and transmission rights

Electricity Journal

Volumn 14, Issue 1, 2001, Pages 34-55

  Ruff, Larry E ^a  

^a STANFORD UNIVERSITY   (United States)

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EID: 0003078138     PISSN: 10406190     EISSN: None     Source Type: Journal    
DOI: 10.1016/S1040-6190(00)00174-3     Document Type: Article

References (27)

1. The term "security-constrained dispatch" (SCD) is more commonly applied to this process, but the term CCD is used here to emphasize the role of dispatch contingencies.
2. Hung-Po Chao and Stephen Peck, A Market Mechanism for Electric Power Transmission, 10 J. REG. ECON., 1996, at 25-59. As discussed below, Chao and Peck propose two, mutually inconsistent ways to deal with CCD in a flowgate /FGR market, neither of which resolve the dilemma.
3. Shmuel Oren in an e-mail to Andrew Ott of the Pennsylvania-New Jersey-Maryland Interconnection (and a large cc list), Sept. 20, 2000. See discussion below.
4. The dispatch is constrained by contingencies even when the grid is in its standard condition, i.e., when none of the contingencies has actually occurred. The issue of who should bear the costs when the grid is not in its standard condition is an important issue but is not considered here.
5. In principle, each of the three line constraints implied by Figure 1 could be interpreted as either an actual or a contingent constraint. But virtually nobody draws such a simple diagram and then says that each constrained line in that diagram actually represents an abstract "element /contingency pair." A "line" almost always represents a physical network element.
6. Whether FGRs are needed for scheduling or only to hedge transactions depends on whether an FGR is regarded as a "physical" right or a "financial" right. Although FGRs are still sometimes called physical rights, it is now generally accepted that FGRs should not be required for scheduling, but are primarily financial hedges. It is assumed here that FGRs are financial instruments but that market participants seek FGR portfolios that reflect their expected physical operations.
7. Even if market participants must submit balanced schedules covered by FGRs, the RTO will have to use a full LMP process to determine the incremental dispatch and the associated prices. Energy traded under balanced schedules covered by FGRs will not be priced or settled in this process, but will affect actual transmission congestion and prices and hence must be an input to the LMP process.
8. Hung-Po Chao, Stephen Peck, Shmuel Oren, and Robert Wilson, Flow-Based Transmission Rights and Congestion Management, ELEC. J., Oct. 2000, at 38.
9. gf) FGRs on all flowgates f will be paid for its FGRs exactly what it pays in congestion charges and hence will be perfectly hedged. Approximate coverage on flowgates with "significant" prices will result in an approximate hedge.
10. This is not just a hypothetical situation, but arises all the time on real systems. For example, operation of the New York system is often constrained by the risk that one of several cables into Manhattan and Long Island might fail and the flows over the remaining cables would surge above line limits.
11. For example, the RTO may impose more stringent - e.g., N-2 - contingency constraints when thunderstorms are in the area, on the grounds that lightning strikes may disable several transformers simultaneously. Who bears the costs when such changes in dispatch contingencies or actual grid conditions reduce grid capacity is an important issue that is essentially the same with either FGRs or FTRs, and hence is not discussed here.
12. For example, in this case if a line could fail partially it would be necessary to consider post-contingency flows on the failed line in each contingency; and larger post-contingency instantaneous flow limits on failed lines - e.g., 150 percent of steady-state limits - could make the constraints on actual flows binding in some dispatches.
13. If the limits on instantaneous, post-contingency flows were higher, the inner boundary in Figure 5 would expand outward, and at some point the two boundaries would overlap.
14. PJM dispatchers reportedly monitor approximately 50 contingencies.
15. A secondary problem is that it is very difficult even to define a set of settlement rules that make sense here. The difficulty of defining a sensible settlement process is creating difficulties for the efforts to develop a workable hybrid at MISO and perhaps elsewhere, but is not discussed here.
16. In this simple case, redispatch would require paying some scheduled /hedged generation in GEN not to run and paying some unscheduled /unhedged generation at LOAD to run out-of-merit.
17. Supra note 2, at 44-46. As discussed below, Chao and Peck suggest a different nonsolution to the problem of too many FGRs in a footnote within their article.
18. Supra note 2, at note 18. As discussed above, Chao and Peck suggest a different nonsolution in the text of their article.
19. There is no FGR portfolio that perfectly hedges congestion on flowgate A in every contingency for all transactions, because different PDFs will apply to each different point-to-point transaction. For the same reason, there is no FGR portfolio that perfectly hedges congestion on all flowgates in contingency X for all transactions. In principle it is possible to create an FGR portfolio that perfectly hedges against congestion on all flowgates in all contingencies for a specified point-to-point transaction. These are called FTRs.
20. William Hogan, Flowgate Rights and Wrongs, working paper, John F. Kennedy School of Government, Harvard University, Aug. 20, 2000, at 20.
21. Andrew L. Ott, Can Flowgates Really Work? An Analysis of Transmission Congestion in the PJM Market from April 1, 1998-April 30, 2000, PJM Interconnection, Sept. 15, 2000.
22. Supra note 3.
23. William W. Hogan, Contract Networks for Electric Power Transmission, 4 J. REG. ECON., 1992, at 211-42. Grant Read of Canterbury University in New Zealand was an early collaborator with Hogan. Read spent some time in the late 1980s and early 1990s developing a link-based approach to transmission pricing and congestion management, but says that he gave it up as hopeless (personal communication to author).
24. F.C. SCHWEPPE, M.C. CARAMANIS, R.D. TABORS, AND R.E. BOHN, SPOT PRICING OF ELECTRICITY (Norwell, MA: Kluwer, 1988).
25. William W. Hogan, E. Grant Read, and Brendan J. Ring, Using Mathematical Programming for Electricity Spot Pricing, in ENERGY MODELS FOR POLICY AND PLANNING, International Transactions of Operational Research, Vol. 3, No. 3 /4, 1996.
26. A dispatch or set of FTRs is said to be simultaneously feasible if it satisfies all of the actual and contingent constraints used for dispatch. To be explicit about what should be obvious but is sometimes confusing, a simultaneously feasible dispatch does not have to be feasible even if all contingencies were to occur simultaneously. No dispatch could meet these conditions.
27. Given the nonconvex nature of electricity systems - economies of scale, integer choices, etc. - such sweeping assertions require some technical qualifications, and it is possible to create counterexamples using unrealistic numerical examples. But the important assumptions of LMP /FTR theory appear to be valid over wide ranges of actual conditions on real systems, in sharp contrast to the assumptions of flowgate /FGR theory, which are virtually never correct (e.g., PDFs are simply not constant).