PJM last week issued its response to the Independent Market Monitor’s latest recommendations, noting that many of the issues are in the scope of current stakeholder discussions.

The Monitor issued 20 new recommendations in its 2021 State of the Market (SOM) report in March: seven concerning the energy market; eight concerning the capacity market; two on demand response; and one each on environmental regulations, ancillary services and financial transmission rights. (See PJM Monitor: Prices, Coal Power Bounced Back in 2021.)

Energy Market Recommendations

PJM said that two of the energy market recommendations — regarding the capping of the system marginal price in real-time security constrained economic dispatch, and implementing an extended downward sloping operating reserve demand curve (ORDC) — were “superseded” by a December 2021 FERC order on voluntary remand from the D.C. Circuit Court of Appeals. (See FERC Reverses Itself on PJM Reserve Market Changes.)

The RTO said it responded to the order with a proposal to retain the existing reserve market and energy market price capping framework “largely consistent” with the SOM recommendation. But it said it has no plans to implement downward sloping demand curves for operating reserves because the commission rejected it.

PJM said it addressed another Monitor recommendation — requiring generators that violate their approved turn-down ratio to demonstrate that their actions are based on an actual physical constraint — in its response to a June 2021 FERC order to show cause. The commission ruled that PJM’s tariff appeared to allow market sellers to circumvent being subject to parameter-limited offers. (See FERC Issues Show-cause Order on PJM Parameter-limited Offers.)

The RTO responded to FERC by instituting an interim rule restricting the use of real-time values to actual physical limitations that occurred during the real-time market. “PJM believes these interim limitations sufficiently address concerns that market sellers could submit real-time values to inappropriately limit their flexibility, since economic reasons for adjusting parameter limits are no longer acceptable reasons to override unit-specific parameters,” PJM said.

However, the RTO disagreed with the Monitor’s proposal to require that capacity resources be required to use flexible parameters in all energy offers at all times to mitigate market power.

“PJM disagrees that capacity resources have broad ‘obligations to be flexible’ under the current capacity market construct,” the RTO said, adding that “flexibility is not an explicit requirement for the qualification for capacity resources [and] is largely not accounted for in the accreditation of capacity resources.”

It also rejected the IMM’s call for adjusting ORDCs during spin events to reduce the reserve requirement for synchronized and primary reserves by the amount of reserves deployed.

“PJM views this recommendation to be inconsistent with the NERC standard that obligates PJM to procure contingency reserves and also with PJM’s policy for maintaining adequate reserves,” it said. “PJM’s current policy regarding reserves is intended to restore reserves as quickly as possible following their deployment. The purpose of this is to make sure that the PJM system can respond to successive contingencies should they occur.”

Capacity Market Recommendations

PJM said the Resource Adequacy Senior Task Force, which began work in December, is discussing a range of potential rule changes that could address several of the Monitor’s capacity market proposals.

Among them:

• that the value of capacity transfer rights be defined by the total megawatts cleared in the capacity market, the internal megawatts cleared and the imported megawatts cleared, and not redefined later prior to the delivery year;
• that the market clearing results be used in settlements rather than the reallocation process currently used, or that the process of modifying the obligations to pay for capacity be reviewed;
• that PJM improve the clarity and transparency of its capacity emergency transfer limit (CETL) calculations and that the CETL for capacity imports be based on the ability to import capacity only where PJM capacity exists and where that capacity has a must-offer requirement;
• using the lower of the cost- or price-based energy market offer to determine energy costs in the calculation of the historical net revenues;
• that any combined seasonal resources be required to be in the same locational deliverability area to ensure the energy and capacity markets remain synchronized and reliability metrics correctly calculated.

Some other recommendations are under discussion in other venues, PJM said.

The Monitor’s call to bar storage and other intermittent resources from offering capacity megawatts based on energy delivery that exceeds their capacity interconnection rights (CIRs) is among the issues being discussed at the Planning Committee’s special sessions on CIRs for effective load-carrying capability resources, PJM said.

The IMM’s call for PJM to re-evaluate the shape of the variable resource requirement curve will be considered as part of the Market Implementation Committee’s current Quadrennial Review, the RTO said.

Demand Response, FTRs

PJM rejected the Monitor’s proposal that electric distribution companies (EDCs) not be allowed to participate in markets as distributed energy resource aggregators in addition to their EDC role.

“This recommendation is inconsistent with FERC Order No. 2222, in which the commission affirmed that ‘market participation agreements for distributed energy resource aggregators should not preclude distribution utilities, cooperatives or municipalities from aggregating distributed energy resources on their systems,” PJM said. “Accordingly, PJM’s DER Aggregator Participation Model, proposed as a component of PJM’s Order 2222 compliance filing, does not prohibit a distribution utility from forming its own DER aggregation resources. This is consistent with current practice today, where certain distribution utilities participate in the PJM demand response program with their own load reduction resources.”

The RTO acknowledged, however, that the DER Aggregator Participation Model, which will “require a greater level of distribution utility coordination to ensure safety and reliability … sets up a scenario in which a distribution utility — the entity responsible for physically operating its distribution facilities and overriding PJM dispatch of other DER aggregators — may also be competing against other DER aggregators connected to those same distribution facilities.”

“PJM acknowledges concerns regarding this potential conflict of interest and anticipates continued dialogue with states and stakeholders on how state and local law may address this issue,” it said.

The RTO’s report renewed its disagreement with the Monitor over the proper confidence interval when calculating initial margin requirements for FTR market participants.

Although the Monitor recommended the use of a 99% confidence interval, PJM proposed 97%, which was rejected by FERC as unsupported by the record. (See Stakeholders Encourage PJM to Defend FTR Filing.)

The RTO maintains that the 97% option is “the most cost beneficial proposal” and that the increased collateral costs at 99% is greater than the benefit in reduced defaults.

“Based on this and other additional analysis, PJM believes it can supplement the December [Federal Power Act Section] 205 filing with additional evidence to support use of the 97% confidence interval to address most of FERC’s concerns,” it said.