By Michael Kuser

FERC on Monday approved ISO-NE’s interim proposal to use an out-of-market mechanism to address concerns about fuel security (ER18-2364).

ISO-NE filed the Tariff revisions after FERC on July 2 denied a Tariff waiver to allow the RTO to enter a cost-of-service agreement to keep Exelon’s 2,274-MW Mystic plant running after its capacity obligations expire in May 2022. The commission instead directed the RTO to revise its rules to allow such agreements in order to address fuel security.

FERC tentatively accepted the Mystic cost-of-service agreement on July 13 while ordering an expedited hearing on unresolved issues. (See FERC Advances Mystic Cost-of-Service Agreement.)

Commissioners Cheryl LaFleur and Richard Glick approved the Dec. 3 order, with Chairman Neil Chatterjee dissenting in part. Commissioner Kevin McIntyre did not participate in the decision.

“We find here that the proposed study process, including the model assumptions and proposed trigger criteria as modified by ISO-NE from the OFSA [Operational Fuel-Security Analysis] and Mystic retirements studies, is just and reasonable,” the commission said. “Nevertheless, we encourage ISO-NE to work with all interested parties, including [the New England Power Pool], to continue to address their areas of disagreement while developing the long-term market solution.”

The commission also directed the RTO to submit “an annual informational filing regarding the applicability of its study triggers, study assumptions and study scenarios compared to actual experiences, starting with the winter of 2022/23, for the duration of this interim mechanism.”

Cost Allocation

In accepting ISO-NE’s proposal to allocate to load the out-of-market costs for retaining fuel-secure resources, the commission agreed “that the goal of the proposed revisions is similar to that of [ISO-NE’s] Winter Reliability Program and therefore should have a similar cost allocation method.”

The commission agreed with the RTO that it is inappropriate to allocate fuel security costs to transmission customers because fuel security concerns are distinct from traditional transmission-related reliability needs.

“Specifically, the reliability need that triggers the proposed revisions is a depletion of 10-minute reserves to a particular level or load shedding, as opposed to the violation of local transmission reliability criteria,” the commission said. “Additionally, unlike reliability-must-run resources, the need for a fuel-secure resource is unlikely to be met by local or pool transmission upgrades.”

Under the revisions, ISO-NE will now enter fuel security resources into the Forward Capacity Market as price-takers, ensuring that their resource adequacy contributions are counted.

With respect to capacity market offers, “there is no meaningful distinction between resources retained for reliability and resources retained for fuel security,” the commission wrote.

In his partial dissent, Chatterjee argued that the RTO’s price-taker provision undermines the fundamental premise for implementing a process to support fuel security, and that lower capacity auction prices will encourage marginal units to retire.

“If these same units also are fuel-secure resources, then this price suppression could lead to a further decline in fuel security,” Chatterjee said. “The result could be a vicious cycle of additional out-of-market interventions for these retiring resources, further price suppression and even more retirements, which, in turn, will only further diminish the region’s fuel security.”

Input Assumptions

The Tariff revisions include a formal fuel security reliability review process for resources submitting retirement delist bids for Forward Capacity Auctions 13, 14 and 15, which correspond to capacity commitment periods 2022/23, 2023/24 and 2024/25, respectively.

The RTO will now apply a uniform set of 18 modeling scenarios to establish whether a resource submitting a retirement de-list bid is needed to maintain regional fuel security.

To measure the operational impact of a specific generator retirement, the RTO will model its system under each scenario, absent the generator that has submitted a delist bid, and model generators in descending order of their bids.

Under the RTO’s proposal, a generator will be retained for fuel security purposes if one of two triggers occur after full utilization of Operating Procedure No. 4 (OP-4), actions taken during a capacity deficiency when available resources are insufficient to meet anticipated electricity demand plus required operating reserves:

Reduction of 10-minute reserves below 700 MW in any hour in the absence of a contingency in more than one LNG-gas supply scenario case; or

The use of load shedding in any hour under OP-7, when the RTO requests that generators and demand response resources not subject to a capacity supply obligation voluntarily provide energy for reliability purposes.

The RTO will use the same model developed for OFSA to assess the need to retain a resource for fuel security. To evaluate the operational impacts of generator retirement delist bids, predefined scenarios will test system performance under a range of scenarios and sensitivities, absent a retiring generator.

Static input assumptions will model a number of system parameters, including winter peak load, winter load profile and local distribution company natural gas demand.

In addition, the RTO will use three variable inputs in the model: LNG injections, electricity imports and the dual-fuel oil tank fill rate, which represents the number of oil refills at dual-fuel generating units per 90-day winter season.

The commission noted that many commenters argued for modifications to the two proposed triggering criteria.

“Some commenters argue that the triggering criteria are too conservative, meaning the criteria are easily violated and will result in unnecessary out-of-market interventions,” the commission said. “Still others argue that the triggering criteria are not conservative enough, meaning that the criteria are not easily violated and will result in an elevated risk to reliability in cold weather months.”

The 700-MW trigger is intended to account for improvements in system performance between the forecast year and the operating year, which are not fully accounted for in the modeling, the RTO said in its filing.

The allowance for reduction of 10-minute reserves in the analysis does not indicate allowance of any violation of NERC operations criteria, the RTO said, adding that it will continue to maintain needed generation reserves to meet mandatory reliability criteria during operation.

Connecticut regulators supported the revised modeling methodology because “it incorporates more recent data that would be updated annually and accounts for resources under state contracts, [and] balances conservative and optimistic approaches to avoid both over-procurement and reliability problems.”

Market Failure

In a concurring opinion, Glick advised that “ISO-NE’s apparent need to retain units for fuel security is the result of a market failure” and that the RTO’s “ultimate approach to fuel security will need to be more sophisticated than the interim approach we approve today.”

Glick added that the favorable ruling for ISO-NE “does not necessarily indicate that even the exact same proposal would be just and reasonable in other regions of the country,” Glick said.

Units needed for fuel security would be economic if compensated for the services they provide, which should be procured through the competitive markets, he said.

“Individual, ad hoc contracts with particular resources whose retirement might, under the most conservative assumptions, create a fuel security concern is no way to address a region’s long-term fuel security,” Glick said.

The Tariff changes became effective Oct. 30.