ISO-NE CEO Gordon van Welie last week shared the RTO’s “vision for the future” with the NEPOOL Participants Committee, which he presented as “our long-term intent” that “guides the formulation of our strategic goals.”

The RTO included a forward-looking statement that van Welie said seeks “to harness the power of competition and advanced technologies to reliably plan and operate the grid as the region transitions to clean energy.”

Publication of ISO-NE’s vision comes on the heels of recent calls for reform by the New England States Committee on Electricity (NESCOE), which wants increased transparency from the RTO and a more prominent role in the decision-making process. (See States Demand ‘Central Role’ in ISO-NE Market Design.)

The RTO’s five “strategic goals” are responsive market designs; progress and innovation; operational excellence; stakeholder engagement; and attracting, developing and retaining talent.

When it comes to the first goal, van Welie said ISO-NE wants to improve the current market structure and continue to evolve and reposition its design to accommodate the states’ transition to high levels of renewable and distributed resources. The RTO also wants to maintain a robust fleet of balancing resources and preserve the market’s ability to attract new entry.

The progress and innovation goal includes a push to evolve capabilities to support the grid as the region transitions to clean energy. It also includes improving power system and market modeling and supporting investments in transmission infrastructure to enable renewable energy, as well as a call for integrating distributed energy resources and providing data and information-based services.

According to van Welie, stakeholder engagement requires collaboratively understanding and anticipating needs, thought leadership through high-quality analysis and communication, and nurturing productive relationships with FERC, the states and market participants.

Amended DDBT Passes

The committee voted to support an amended proposal from ISO-NE to recalculate the dynamic delist bid threshold (DDBT) for Forward Capacity Auction 16.

Calpine, NESCOE and Vistra’s Dynegy offered a combined amendment to the RTO’s proposal to lower the DDBT upper bound to 75% of the net cost of new entry (CONE) and set the DDBT at the RTO’s estimated clearing price plus a margin adder calculated using 75% of net CONE.

NESCOE said it remains concerned that the ISO-NE proposal does not balance design objectives and can result in the DDBT being set too high when capacity prices increase. The organization added that the risk of the DDBT being higher, especially as it approaches net CONE, could have cost implications for consumers.

Calpine and Dynegy said the RTO’s design interferes with competitive price formation, adds significant administrative burden and risks to existing suppliers, and creates an unnecessary barrier to market exit. The amendment allows a modest margin adder to low prices when supply curves are typically flat, with the adder diminishing as expected prices increase, which preserves at least some of the benefit of the DDBT.

Previously, NESCOE presented two amendments at the Markets Committee meeting in October. One would have lowered the upper bound to 85% of net CONE and add an upper bound set at 125% of the prior auction clearing price. The second would have limited the maximum rate of change in the DDBT from auction to auction to 30% of net CONE.

Calpine and Dynegy also presented amendments at the MC that would set the DDBT at ISO-NE’s estimated clearing price plus a scaled margin that starts 75 cents above the RTO’s estimated cost of $2/MWh, decreasing to $0/MWh at net CONE, or, as an alternative, from a fixed bid to a cap price.

At the RTO’s request, the committee considered, but did not approve, the unamended DDBT proposal. The vote failed to pass with none in favor and noted abstentions.

Pathways Process Continues

Frank Felder and Frank Wolak each made presentations on “Potential Pathways to the Future Grid,” with Felder returning for “Focus on Energy Only Market and Alternative Resource Adequacy Constructs” and Wolak discussing “Long-Term Resource Adequacy with Significant Intermittent Renewables.”

Felder, a professor at Rutgers University and an expert in energy policy and electricity markets, told the committee that whether the minimum offer price rule (MOPR) applies to a forward clean energy market or integrated clean capacity market determines the potential for “double payment” for clean energy and price suppression. He said an energy-only market addresses the double payment issue and maintains a regional market, even more so with added carbon pricing. Additional changes to the ancillary services markets may be needed, however, to ensure sufficient balancing resources.

According to Felder, some alternative resource adequacy constructs could address the MOPR issue. He added that anticipated replacement of large generating resources throughout New England with new capacity with very different operating characteristics suggests the region will need to strongly consider changes to transmission planning and cost allocation to avoid costly investment decisions.

Wolak, a Stanford University economics professor and director of its program on energy and sustainable development, said that in a low-carbon world, the electricity supply sector would consist of more than 50% intermittent renewables.

Wolak said the growing share of renewables will also require investments in both grid-scale and distributed storage and active demand-side participation by customers with interval meters using dynamic retail electricity prices, in addition to automated distribution network monitoring and on-site load-shifting technologies. He added that market design should support business models that lead to efficient investments in those technologies.

Winter is Coming

In his report to the committee, ISO-NE COO Vamsi Chadalavada said that the energy market’s value was $193 million in October, down $14 million from revised September figures and $9 million from October 2019.

Chadalavada also delivered the winter outlook, including a 40% probability of above-normal temperatures for New England from December through February. There is also an equal chance for above- or below-average precipitation in the region.

In terms of winter capacity, Chadalavada said ISO-NE is projecting the lowest 50/50 operable capacity margin of 2,574 MW and a 90/10 capacity margin of 1,232 MW for the week beginning Jan. 2, 2021. The capacity outlook will be adjusted if there are extended periods of cold weather.

The 50/50 winter peak demand forecast of 20,166 MW is 310 MW lower than the 2019/20 forecast, while the 90/10 winter peak demand forecast of 20,806 MW is down by 367 MW.

Chadalavada added that unknown societal factors would likely continue to impact demand throughout the season. He said forecasting staff are continuously evaluating load trends and frequently retraining forecasting models.

The RTO also recently hosted a Generator Winter Readiness Seminar and distributed a survey to all regional generating resources. It said survey results will enhance its understanding of winter preparations across the region, temperature-specific limitations on real-time capabilities and specific protocols followed during extreme cold-weather events.

ISO-NE will continue to perform a weekly 21-day look-ahead of forecasted conditions, which provides an opportunity for generators to act in advance of an energy emergency. In addition to the Winter Generator Readiness Survey, the annual natural gas critical infrastructure survey process has been incorporated into Operating Procedure 21 before winter.

Other Action

The committee also acted on consent agenda items.

Without objection, the PC removed sunset of the forward reserve market (FRM) from the consent agenda following FERC’s Oct. 30 order rejecting the Energy Security Improvements (ESI) proposal on which the FRM sunset was contingent. (See FERC Rejects ESI Proposal from ISO-NE.)

The remainder of the consent agenda was approved with two abstentions and two oppositions because of concerns about the installed capacity requirement (ICR) and related values for Forward Capacity Auction 12’s three annual reconfiguration auctions (ARAs) set for 2021.

The PC approved net ICRs of 32,925 MW for ARA 3, 32,765 MW for ARA 2 and 32,980 MW for ARA 1. The HQICC value is 958 MW for ARA 3, with the amount rising to 969 MW for ARA 2 and down to 941 MW for ARA 1.