By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM’s Independent Market Monitor and the RTO are at odds over whether generators should receive additional compensation for providing FERC-mandated primary frequency response.

PJM led most of last week’s meeting of the Primary Frequency Response Senior Task Force because, aside from the compensation issue, the Monitor’s proposal is nearly identical to the RTO’s. But that single issue attracted criticism from stakeholders. (See “Market-Based Frequency Response Solution Hard to ID,” PJM Operating Committee Briefs: Nov. 7, 2017.)

The Market Monitor argued that compensation for primary frequency response, in terms of capacity costs, avoidable maintenance costs and any heat rate loss is already accounted for in PJM’s existing capacity and energy markets.  That position is “kind of a nonstarter from a generator side,” American Electric Power’s Brock Ondayko said. The payments are necessary because the revenue provided by PJM’s capacity and energy auctions are “nowhere near the supporting levels for those types of resources,” he said.

Howard Haas of Monitoring Analytics argued that all of the costs involved in providing primary frequency response are baked into the market already through the cost of new entry calculation and should be included in resources’ capacity auction offers. PJM’s interconnection agreement requires all new units to provide the service.

“There is an obligation to provide the service,” Haas said. “To the extent that you’re eligible to participate in the capacity market … you have the opportunity to recover associated capacity costs and any going-forward, avoidable costs. … The capacity market does not make a distinction between new and old units, and the CONE unit includes the capability to provide the service.” (See FERC Has More Questions on Frequency Response NOPR.)

Providing primary frequency response isn’t new to PJM, and any heat-rate losses can be accounted for in the 10% adder included with energy-market offers, he said.

Ondayko dismissed that, saying the only way to receive auction revenue is to offer well below the unit’s costs.

Haas acknowledged that the natural gas boom “turned the market upside down” and that “the prices are low.” But he said prices are low, in part, because “the market is long on supply” and uneconomic units should retire.

“You can get up to one-and-a-half times CONE if the market is short. It’s not,” he said.

Tom Hyzinski of GT Power Group questioned Haas on competition from demand response, which doesn’t provide the inertial benefits necessary for frequency response. Haas agreed that DR should be a demand-side product rather than supply and said more needs to be done to address speculative DR offers. However, load is not required to sign an interconnection agreement.

The Argument for Compensation

PJM’s Glen Boyle said “there is a cost” to providing primary frequency response. “We want to offer a way to recover it similar to reactive supply,” he said.

He envisioned a process similar to PJM’s current payment for reactive power in which market participants make an informational filing with FERC, which directs the RTO on how much to compensate the filer. The requests would need to be newly incurred costs that are not included in the unit’s variable operations and maintenance (VOM) calculations.

“We really need stakeholder feedback on what they think the costs would be,” Boyle said.

Those determinations might get tricky. When one stakeholder calling into the meeting suggested there might be ongoing costs for maintaining the operational flexibility to increase or decrease output, PJM’s Eric Hsia said those sounded like lost opportunity costs, which FERC likely wouldn’t accept.

He said compensation would have to focus on operations and maintenance costs like those incurred for maintaining a heat rate. He said care would be taken to write the rule such that generators can’t “double dip” on costs they’ve already recovered.

Carl Johnson, who represents the PJM Public Power Coalition, questioned the wisdom of having generators file at FERC. “We’re going to struggle with just allowing anybody going in with anything they deem reasonable,” Johnson said.

Stakeholders also debated whether traditional generators with large rotating masses that produce synchronous inertia provide different benefits than renewables with converter-based “synthetic” inertia and should be compensated differently.

Ondayko said such issues should be included in the primary frequency response discussion; otherwise the discussion would be “missing out” on the “mix of resources” necessary to provide grid-scale inertia, he said.

Other Factors

PJM’s proposal would analyze primary frequency response performance by measuring the difference between the RTO’s requested action during a frequency event and how the unit responds when called. Units would have to be online and providing energy, operating between their minimum and maximum real-power output, with available headroom or footroom and assigned Tier 1 or Tier 2 reserves. The analysis would include a pass-or-fail threshold.

“We would take into account the available headroom or footroom and the expected response would reflect that,” said PJM’s Danielle Croop, adding that the analysis wouldn’t “nitpick” on small changes in performance.

Units that are providing frequency regulation wouldn’t be assessed. Nuclear units would still be exempted, as would units that are going to be deactivated and units with technical limitations. Operators would need to submit exemption requests within six months of the rule going into effect.

Stakeholders noted that some units can’t set their deadband operation — which represents the upper and lower bands of acceptable operation — and that retrofits would be prohibitively expensive on units with exceptionally low capacity factors, particularly because they usually run when there are plenty of other units online to provide primary frequency response.

PJM’s Vince Stefanowicz hesitated to agree, saying that during a restoration scenario where frequency regulation hasn’t yet been established, “primary frequency response is kind of our first line of defense.”

Johnson asked if there was a frequency event during the expectedly cold temperatures in the winter of 2014 often referred to as the polar vortex. Hsia said staff are looking into it.

The task force’s next meeting is Dec. 20, when stakeholders will discuss implementation details, including concepts proposed by Dominion Energy.