Scarcity, market power, and price caps in wholesale electric power markets

Electricity Journal

Volumn 13, Issue 9, 2000, Pages 33-46

  Wilson, James F ^a  

^a Law and Economics Consulting Group   (United States)

Author keywords

[No Author keywords available]

Indexed keywords

COMMERCE;

ELECTRIC POWER MARKETS; INDEPENDENT SYSTEM OPERATORS; MARKET POWER; MARKET PRICE; PRICE CAPS; TIGHT SUPPLY;

ELECTRIC UTILITIES;

EID: 0034311514     PISSN: 10406190     EISSN: None     Source Type: Journal    
DOI: 10.1016/S1040-6190(00)00153-6     Document Type: Article

References (25)

1. 1. See, for instance, May Spike Prods Utility, ISO-NE to Seek Limits in New England Prices, Inside FERC, June 19, 2000; Search for Answers on NW Market Volatility Pressures WSCC, Clearing Up, July 7, 2000.
2. 1. See, for instance, May Spike Prods Utility, ISO-NE to Seek Limits in New England Prices, Inside FERC, June 19, 2000; Search for Answers on NW Market Volatility Pressures WSCC, Clearing Up, July 7, 2000.
3. 2. See, for instance, 89 FERC 61,169, Order Accepting Tariff Revisions and Granting Waiver of Notice, issued Nov. 12, 1999; or 88 FERC 61,315, Order Accepting for Filing Revisions to Operable Capability Market Rules, issued Sept. 30, 1999.
4. 2. See, for instance, 89 FERC 61,169, Order Accepting Tariff Revisions and Granting Waiver of Notice, issued Nov. 12, 1999; or 88 FERC 61,315, Order Accepting for Filing Revisions to Operable Capability Market Rules, issued Sept. 30, 1999.
5. 3. California ISO Board of Governors Approves Lowering Price Caps Temporarily, California ISO press release, June 29, 2000.
6. 4. 92 FERC 61,065, NSTAR Services Company v. New England Power Pool, issued July 26, 2000.
7. 5. See, for instance, California ISO Market Surveillance Committee's Report on Redesign of California Real-time Energy and Ancillary Services Markets (MSC's October Report), Oct. 18, 1999.
8. 6. PJM Interconnection State of the Market Report 1999, Market Monitoring Unit, PJM Interconnection, LLC, June 2000.
9. 7. California ISO, Short-term Price Cap Policy Options, June 21, 2000.
10. 8. Curt Hebert, Jr., dissenting in 92 FERC 61,073, New York Independent System Operator, Inc., issued July 26, 2000.
11. 9. Countervailing or mitigating factors could include market allocation and pricing of all output in forward markets, or government regulation of prices and allocation under such circumstances. Due to uncertainties about supply and demand, however, spot markets (legal or illegal) are likely to form, and prices in them are likely to be volatile.
12. 10. For energy-limited resources such as hydroelectric, production at any time reduces the "fuel" (water) available to produce at a future time, and the opportunity cost must be taken into consideration in pricing current output. Sellers must determine the value of the limited water based on forecasts of future prices and water availability, and price current output to reflect this "water value" and the resulting opportunity cost. Even if such energy-limited resources are frequently the marginal producers in a market, prices may still be volatile if water availability and resulting water value varies considerably across the available resources. Limits on other key inputs, such as environmental permits, can have the same impact on pricing strategies.
13. 11. This assumes a unit is already online. Start-up and minimum load costs must also be taken into account in unit commitment decisions. Ramping constraints can also create opportunity costs, as producing (not producing) in one period may require (preclude) some production in adjacent periods for slow-ramping units.
14. 12. Sellers will still offer output into bilateral and forward markets at prices that reflect the expected market value of the output. The opportunity cost of any available transaction reflects the potentially higher willingness to pay of another trading partner, and the expected market price in closer to real-time markets. Even in real-time markets, depending upon market design, sellers may simultaneously bid into energy and ancillary services markets, and may have to bid into each market based on the opportunity cost of foregoing the other markets. Opportunities to sell into markets in other regions introduce an additional opportunity cost that may be reflected in bids.
15. 13. The demands for ancillary services are determined by ISOs or utilities based on reliability considerations, and are generally specified as fixed quantities rather than demand curves - despite the fact that having more of them provides additional reliability, but less will generally be cheaper. Recognition of the logic of buying more ancillary services when they are cheaper and less when they are very expensive is growing. For instance, demand curves for ancillary services are proposed as an element of the New England congestion reforms. See Filing of ISO New England, Inc., Relating to a Congestion Management System and a Multi-Settlement System for the New England Power Pool, FERC Docket No. EL00-62, March 31, 2000.
16. 14. There are many complexities to such a determination, such as whether average consumer willingness to pay, or some other basis (median, 90 percent level, etc.) should be considered. A discussion of how the value of service or a demand curve for ancillary services should be determined is beyond the scope of this article. There is a substantial body of research regarding the value of electric service; with regard to a demand curve for ancillary services, see Peter Cramton and Jeffrey Lien, Eliminating the Flaws in New England's Reserve Markets, March 2, 2000, http:// www.cramton.umd.edu (Nov. 1, 2000).
17. 15. NSTAR Services Company v. New England Power Pool, supra note 4. In approving a price cap, the order observed that prices "may exceed the value of electricity to at least some retail customers."
18. 16. In principle, the value of an increment of reserves should reflect the likelihood that it will actually be called upon, and its value in avoiding lost load when called upon.
19. 17. For a discussion of energy-only and installed capacity markets, see Steven Stoft, PJM's Capacity Market in a Price-Spike World, University of California Energy Institute, May 2000.
20. 18. NYISO Revised Market Mitigation Measures and transmittal letter, filed on Dec. 23, 1999, and NYISO Market Mitigation Measures Compliance Filing, FERC Docket No. ER97-1523, April 18, 2000.
21. 19. See, for instance, U.S. Department of Justice and the Federal Trade Commission, Horizontal Merger Guidelines, rev. April 8, 1997.
22. 20. For a summary of the legal requirements for FERC to rely upon market-based pricing, see NSTAR Services Company v. New England Power Pool, Complaint of NSTAR Services Company Requesting Fast Track Processing and Prayer for Emergency Relief, FERC Docket No. EL00-83, June 13, 2000.
23. 21. FERC Directs a Probe of Bulk Power Markets, FERC press release, July 26, 2000.
24. 22. Single Bidder Sent New England Prices to $6,000, Public Power Weekly, May 29, 2000.
25. 23. Joe Bowring, Market Monitoring Manager, in presentation to Edison Electric Institute Economics Committee, May 4, 2000.