By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM on Tuesday rolled out a proposal to procure reserves on a more granular level, a move the RTO hopes will shift more generator revenues back into the energy market.

“I do think that, philosophically, energy is the primary product in these markets,” PJM’s Stu Bresler said at a July 17 meeting of the Energy Price Formation Senior Task Force.

PJM is “not pricing reserves as well as we could,” Bresler said, adding that he expects the revenue distribution between energy and capacity markets to effectively work itself out if reserves prices are developed “as right as we can” make them.

The meeting began with PJM’s Cheryl Mae Velasco and Patricio Rocha-Garrido explaining that under current rules, a unit’s capacity can count as both synchronized reserves and more general primary reserves (which includes non-synchronized reserves), and that a unit would be compensated at a price that reflects providing each. For example, a unit can count as both $20/MW synch and $10/MW primary reserves and be paid a combined $30/MW. The amounts are calculated using “shadow prices” indicated by operating reserve demand curves (ORDCs) that are based on the probability of falling below the minimum reliability requirements for synch and primary reserves.

The shadow prices can vary extensively based on system circumstances, and even fall to $0/MWh, but the penalty factors are capped at $850/MWh. The payment, which is then also combined with a locational LMP, is designed to entice units to respond when called upon.

Shifting the Curves

PJM’s Angelo Marcino discussed staff’s thoughts on how the ORDC can be adjusted to give grid operators more operational flexibility but still make sure that activity is captured in the market. They had been considering developing an “extreme day” ORDC but are now looking at revising on a case-by-case basis to adjust the reserve requirement rather than the slope of the curve, he said. The changes would be classified as either “market” adjustments that are determined through PJM’s clearing engine or “out of market” adjustments that grid operators assign based on issues observed that are not modeled in the RTO’s software.

PJM would ensure real-time notification of the adjustments and be responsible for keeping a historical record of them.

PJM’s Lisa Morelli also discussed staff’s concerns that current reserve zone modeling of the RTO zone with the Mid-Atlantic Dominion (MAD) sub-zone “doesn’t always accurately reflect the constraints dispatch is most concerned with overloading,” which can exacerbate constraints and result in reserve prices that don’t accurately reflect system conditions.

PJM is recommending including nodal reserve pricing and flexible sub-zone modeling in the task force’s discussion. The RTO would define several reserve sub-zones but only tackle one at a time. They could be defined by three categories of constraints: reactive transfer interfaces; 345-kV or larger actual overload constraints; or contingency overloads exceeding the load dump limit on a facility that is 345 kV or larger. PJM would notify participants about their use as early as possible, but provide at least one day’s advance notice.

Each subzone would have its own ORDCs for synch and primary reserves that would remain consistent with the RTO-wide methodology. Staff confirmed that units that hadn’t been assigned for reserves and are offline for some other reason wouldn’t be eligible to receive primary reserve payments.

‘Philosophical Issues’

The proposal sparked discussion from stakeholders about the potential implications.

Susan Bruce, representing the PJM Industrial Customers Coalition, said she was “comforted” to hear that the issues the proposal is meant to address don’t happen often but said she has “philosophical issues” with the market ramifications.

“PJM benefits as a reserve-sharing concept,” she said.

Bresler’s comments about energy as a primary market prompted Roy Shanker, a consultant for several generators, to warn that when the energy and ancillary services markets become “large enough, the behavior of the demand curve has to be examined.”

Bresler agreed that the capacity market’s variable resource requirement demand curve and the energy market’s ORDCs are connected.

Bruce asked that PJM and its Independent Market Monitor attempt to find “areas of consensus” on the topic.

“As much as can be done to narrow those gaps, especially from a customer perspective, that would be highly valued,” she said.

Bresler said staff are “working pretty hard” with the Monitor to come to agreement and that “the sooner that happens, the better off we and the stakeholder community will be.”

PJM also remained noncommittal on Bruce’s request for simulations to see how the proposal shifts revenues between the capacity and energy markets.

“Certainly industrial customers are concerned given their high volume usage,” she said.

PJM staff expressed concerned that stakeholders would judge the proposals on the simulated outcomes rather than the logic of the methodology.

“We do want to have principled reasons for the changes we’re making,” Bruce said, but she added that insight into the potential impact “would be a useful tool … so we can make the right choices before it’s too late.”

James Wilson of Wilson Energy Economics, who consults for several member states’ consumer advocates, said he was interested in “understand[ing] the consequences at a nitty-gritty level, not at an aggregate level.”

Bresler said that could be helpful with the caveat that nothing can be extrapolated to suggest larger consequences.

The meeting concluded with PJM’s Vince Stefanowicz explaining the next steps for developing the real-time 30-minute reserves product. The operational justification and methodology for defining the procurement target were endorsed at the July meeting of the Operating Committee and are moving on to be considered by the Markets and Reliability and Members committees. (See “Real-time 30-minute Reserves,” PJM Operating Committee Briefs: July 10, 2018.)

The price formation task force will focus on pricing the reserve target and optimizing with other ancillary services, determining what resources are eligible and coordinating real-time dispatch, he said.

GT Power Group’s Dave Pratzon asked that the discussion include an analysis to identify why the reserve deficiencies are occurring in the first place.