Congestion pricing or monopoly pricing?

Electricity Journal

Volumn 13, Issue 3, 2000, Pages 33-41

  Rosenberg, Alan E ^a  

^a Brubaker/Associates Inc   (United States)

Author keywords

[No Author keywords available]

Indexed keywords

TRAFFIC CONGESTION;

ACTUAL COST; CONGESTION PRICING; LOCATIONAL MARGINAL PRICING; MONOPOLY PRICING; REDISPATCH;

COSTS;

EID: 0034164889     PISSN: 10406190     EISSN: None     Source Type: Journal    
DOI: 10.1016/S1040-6190(00)00094-4     Document Type: Article

References (30)

1. 1. See ISO Principle No. 8, Federal Energy Regulatory Commission, Order No. 888, Section IV.F.4. and FERC, Regional Transmission Organizations, Docket No. RM99-2-000, Notice of Proposed Rulemaking, Section III.D.
2. 2. FERC, Regional Transmission Organizations, supra note 1.
3. 3. FERC, California ISO, Order Conditionally Accepting Proposed Tariff Changes, May 3, 1999.
4. 4. William W. Hogan, Restructuring the Electricity Market: Institutions for Network Systems, April 1999, accessed on his Web site at http://ksgwww.harvard.edu/ people/whogan/.
5. 5. In a recent report on changes in transmission pricing, ESBI Alberta Ltd., the independent transmission administrator of the Alberta grid, considered LMP and rejected it because of its volatility. See 1999/2000 Phase II General Rate Application of the Transmission Administrator.
6. 6. In this context, incremental costs are defined as the costs associated with physical expansion of transmission capacity through additional investment in transmission plant.
7. 7. One notable exception is PECO Energy. There may be other exceptions as well.
8. 8. If some type of hedging mechanism is not in place to return congestion rents, these revenues should be used to reduce the embedded revenue requirement.
9. 9. In Order 61, 247, FERC expressed its concern that the absence of FTR, or some comparable mechanism, "impermissibly disadvantages the bilateral transmission market." While the notion of a TCC may be thought of as a financial hedge and an FTR may be thought of as a physical right, this article does not attempt to distinguish the relative merits of the two concepts. For purposes of discussion, the terms can be used interchangeably without detracting from the argument.
10. 10. In its Profile on Electricity Issues, March 1997, Electricity Consumers Resource Council (ELCON) issued a position paper that specifically states that an RTO should not make the market, guarantee market outcomes, or operate a spot market or a power exchange.
11. 11. In this case, there would need to be a separate market where generators would bid the prices at which they would be willing to be constrained on or constrained off.
12. 12. It should be noted that this same siting difficulty is often associated with new generation facilities. Thus, the same value-of-service pricing example described here is applicable to generation prices for facilities located in load pockets.
13. 13. See William Hogan, Contract Networks for Electric Power Transmission, J. Reg. Econ., Sept. 1992.
14. 14. Some readers may opine that the marginal cost at Node 2 is only $25 per MWh because that is the clearing price for D, the last generator dispatched. However, by changing the load at Node 2 to just slightly over 200 MW, or restricting the transfer capacity to slightly under 50 MW, we actually would need to dispatch Generator C. While the math would be somewhat more messy, the import of this example would be unchanged.
15. 15. I assume here that the consumers in question do not possess TCCs to hedge the congestion charges or that the cost of those hedges offset the benefits.
16. 16. The author acknowledges that in some circles the term competitive pool is an oxymoron.
17. 17. It should be noted that in practice higher-variable-cost generation bids would likely include some reasonable profit margin and/or contribution to fixed costs in their bid, unless those generators have also made capacity sales.
18. 18. Analysis has shown that in many instances we can expect generators to bid prices that are higher than their variable costs (including some reasonable profit margin). See, for example, Aleksandr Rudkevich, Max Duckworth, and Richard Rosen, Modeling Electricity Prices in a Deregulated Generation Industry: The Potential for Oligopoly Pricing in a Poolco. Energy J. Vol. 19, No. 3, 1998. Readers may wish to ponder how generators may alter their bids to best take advantage of this situation. For example, in the congestion case we are considering, generator D may wish to bid considerably more than $50 per MWh since it will be the "swing" generator at Node 1 with only slightly more load. In that case, our little example may understate the consumer loss and the monopolist gain.
19. 19. Since in this example we are focusing only on incremental or decremental profit, we can legitimately ignore fixed costs for purposes of our analysis and define profit as price less variable cost.
20. 20. In this example we assume full subscription to the available TCCs of 50 MW.
21. 21. Even if Generator C's variable cost and bid were $26 MWh instead of $50 MWh, Node 2 Consumers would pay $200 extra, or four times the actual redispatch cost of $50.
22. 22. While it is true that holders of a TCC will know how much the price will cost in advance, at the end of this article the author will show that TCCs are not a panacea for the serious problems of LMP.
23. 23. James C. Bonbright, Albert L. Danielsen, and David R. Kamerschen, Principles of Public Utility Rates (Public Utilities Reports, 2nd ed., 1988).
24. 24. Steven Stoft, Congestion Pricing with Fewer Prices than Zones, Elec. J., May 1998.
25. 25. The interested reader should be able to convince himself that the generation at Node 1 is (D + 3L)/2 and at Node 2 it is (D - 3L)/2 where D is the Demand and Node 3 and L is the thermal limit between Node 1 and Node 2. Note that the two TCCs are simultaneously feasible since the net TCC flow between Node 1 and Node 2 would be 100 MW. Also, note many other possible combinations of TCCs that would lead to full subscription. In all cases full subscription of TCCs would result in a net TCC flow of 100 MW from Node 1 to Node 2 and net congestion rents of $3, 000.
26. 26. The result is that nonfirm users of the transmission system have to pay congestion charges to have their power moved when congestion occurs since they do not have FTRs. Firm users only pay congestion charges if they deviate from their firm transmission rights. FTRs are awarded such that if there is no nonfirm use and firm users stick to using their FTR rights, redispatch will very rarely, if ever, be required.
27. 27. New York market orientation course given by New York ISO.
28. 28. Docket No. ER98-3594-000, at 8. While California did not technically accept LMP, the author believes this observation is relevant to the LMP issue.
29. 29. Id., at 20.
30. 30. Docket No. RM-99-2-000. Regional Transmission Organizations. Notice of Proposed Rulemaking Part 35.34 (j) (2), May 13, 1999.