By Rich Heidorn Jr.
PJM’s Independent Market Monitor last week gave his blessing to the RTO’s Base Residual Auction for delivery year 2019/20 but called for additional rule changes to build on the tougher standards of Capacity Performance.
The Monitor’s report on the May auction concluded that the results “were competitive, with the caveat that although the Capacity Performance design addressed the most significant issues with the capacity market design, the Capacity Performance design was not fully implemented in the 2019/2020 BRA and there continue to be issues with the capacity market design which have significant consequences for market outcomes.”
PJM will require all capacity to meet CP standards starting with the 2020/21 delivery year.
The Monitor called for additional changes concerning the treatment of pseudo-tied generation, demand response and energy efficiency; the calculation of net revenues; and the application of the minimum offer price rule (MOPR).
The Monitor also acknowledged that its call for using the lower of the cost- or price‐based offer in the calculation of net revenues was rejected by FERC in June (EL14-94-001, ER16-1291). (See “FERC Won’t Revisit Cost-Based Energy Offer Cap Ruling,” PJM News Briefs from FERC Open Meeting.)
But he said the FERC-approved approach used in the May auction, which always uses the cost‐based offer, “resulted in an increase of [$43.4 million], or 0.6%, in the cost of capacity in the 2019/20 BRA.”
In addition, the Monitor recommended:
- All costs incurred as a result of a pseudo-tied generator be borne by the unit and included in its capacity market offers.
- The “electrical proximity” of pseudo-tied resources be “explicitly accounted for” when defining how external resources should be treated during performance assessment hours.
- Enforcing “a consistent definition” of capacity resource as a physical resource at the time of the auctions — with a commitment to be physical in the delivery year and moving all DR to the demand side of the market. The Monitor referenced its 2013 report on replacement capacity, in which it warned that “speculative” DR can suppress prices in the BRA and displace physical generation: “Under the current application of the rules, DR providers may not have identified customers, may not have clear plans for implementing DR measures and may not receive commitments from new customers until relatively close to the delivery year and well after the RPM BRA is run for that delivery year. This is not consistent with the rules.”
- Ensuring the net revenue calculation used to establish the net cost of new entry “reflect the actual flexibility of units in responding to price signals rather than using assumed fixed operating blocks that are not a result of actual unit limitations.” Reflecting actual flexibility will result in higher net revenues, which affect the demand curve and market outcomes, the Monitor said.
- Eliminating the rule requiring that small proposed increases in the capability of a generator be treated as planned for purposes of mitigation and exempted from offer capping.
- Changing the MOPR review to require all projects use the same modeling assumptions. “That is the only way to ensure that projects compete on the basis of actual costs rather than on the basis of modeling assumptions,” the Monitor said.
- Extending the MOPR to existing units in addition to new units.
- Re-evaluating the market mitigation exemption granted DR and energy efficiency resources in 2009. “In 2009, there was one product defined for capacity, and there were no resource constraints defined,” the Monitor said. “Particularly in [locational deliverability areas] with few suppliers, there is now the potential for DR and EE providers to exercise market power and affect the clearing price.”
- Changing the RPM solution methodology to explicitly incorporate the cost of make-whole payments in the objective function.
- Removing energy efficiency resources from the supply side of the capacity market to reflect the change in PJM’s load forecasts. (See Changes to PJM Load Forecast Cuts Benchmark Peaks.) “If EE is not included on the supply side, there is no reason to have an add-back mechanism,” the Monitor said. “If EE remains on the supply side, the implementation of the EE add-back mechanism should be modified to ensure that market clearing prices are not affected.”
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The Utilities Board unanimously denied landowners’ request for a permanent stay of construction of the Dakota Access pipeline pending a court ruling on whether eminent domain can be used to access their properties.
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The New York Power Authority will pay Entergy a $35 million termination fee if the sale of the FitzPatrick nuclear plant to Exelon falls through.
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American Electric Power has asked the Public Utilities Commission for permission to increase the fixed monthly distribution charges for all of its customers to make up for the number of residential customers who are installing rooftop solar and energy efficient technology.
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The Federal Aviation Administration is standing by its previous determination that the proposed Chapman Ranch wind farm in South Texas would “not have an adverse effect on the safe and efficient use of the navigable airspace” primarily used by the U.S. Navy for training pilots out of Kingsville and Corpus Christi.
The Tennessee Valley Authority has filed a request with the Nuclear Regulatory Commission to allow power uprates at its Browns Ferry Nuclear Plant.
Environmentalists are challenging a Bureau of Land Management plan to lease more than 19,000 acres of federal land in Montana for oil and gas exploration.
