NYISO Monitor: Q3 Energy Prices Up Sharply Y-o-Y

NYISO energy markets performed competitively in the third quarter of 2021, with all-in prices ranging from $38/MWh to $117/MWh, up 62% to 94% from 2020 in all regions except New York City, which saw a decrease of 16%, the Market Monitoring Unit said.

“So there was quite a large spread, with particularly high prices in Long Island,” said Pallas LeeVanSchaick of Potomac Economics as he presented the quarterly report on the ISO’s electricity markets to the Installed Capacity/Market Issues Working Group.

Energy prices rose 68% to 124% primarily because of higher gas prices, which rose 110% to 139% across the system. The exception was New York City, which saw a decrease driven by lower capacity prices resulting from a lower locational capacity requirement, he said.

Third quarter 2021 natural gas and fuel oil prices in the New York Control Area. | Potomac Economics

 

Nuclear output fell by an average of 820 MW/hour following the retirement of Indian Point 3.

Both 345-kV lines from upstate New York to Long Island were out of service for more than half of the days during the quarter, LeeVanSchaick said, which led to some “pretty extraordinary conditions on Long Island, very tight, with very volatile pricing.”

He said the loss of the lines resulted in several “inefficiencies” including:

• Lack of reserve shortage pricing during Long Island capacity deficiencies;
• Understated reserve requirements in the day-ahead and real-time markets;
• Inflexible generator scheduling related to gas-balancing charges; and
• Over-accreditation of capacity for some conventional Long Island generation.

NYISO was able to substantially reduce the use of out-of-market dispatch to manage congestion on Long Island because they started modeling two 69-kV facilities, which were constrained on more than 80% of the days in the quarter, LeeVanSchaick said.

Despite several heat waves, load exceeded 30 GW on just one day, and transmission owners activated utility demand response on 10 days, mostly for peak-shaving.

NYISO applied supplemental resource evaluation (SRE) — a determination of the least-cost selection of additional generators to be committed — for statewide capacity needs on three days. Some of those SREs probably would not be necessary if there was more consideration of the utility DR deployments that are going to be called before the ISO makes the decisions, LeeVanSchaick said.

The Monitor identified several categories of conventional generating capacity that may receive excessive accreditation under the current rules, which he said should be evaluated further.

“We do also still observe large quantities of out-of-merit commitment for operating reserve requirements that are not adequately reflecting the day-ahead and real-time markets … both at the larger level as well as in more localized areas,” he said.

Reserve Enhancements for Constrained Areas

Pallavi Jain, energy market design specialist, presented a study evaluating the feasibility of dynamically scheduling reserves in the security constrained unit commitment (SCUC), real-time commitment (RTC) and real-time dispatch (RTD) intervals

“We’re looking at dynamically scheduling reserves because the current static modeling of reserves and the associated requirements may not optimally reflect the varying needs of the grid to respond to operating conditions,” Jain said.

Based on all the mathematical formulations and the prototype, the ISO has determined that it is feasible to set dynamic reserve requirements based on the single largest contingency systemwide and using the available transmission headroom. However, this concept would need to be further developed and its applications to all reserve areas would need to be evaluated, Jain said.

National Grid pipeline sections stacked during construction. | National Grid

 

The ISO made several recommendations, such as considering revising the approach for the determination of the single largest contingency from the current static requirement to a more dynamic methodology; applying the dynamic reserves approach to all reserve areas; and keeping the methodology consistent between the day-ahead and real-time markets to the extent practical.

Senior Manager Tariq N. Niazi presented a consumer impact analysis of the reserve enhancements for constrained areas, which looked at four scenarios based on conditions on Aug. 5, 2021, a hot summer day.

In three of the scenarios LBMPs decreased between $0.60/MWh and $2.60/MWh in different load zones and reserve clearing prices increased by less than $0.10/MWh in the reserve areas. A fourth scenario found an insignificant change in prices.

The ISO will continue working on the prototype in hopes of completing a market design proposal by December 2022 and implementation in 2025.

Coordinating Tx and Distribution

NYISO also updated stakeholders on a project to ensure coordination between transmission system operators (TSOs) and distribution system operators (DSOs) in compliance with FERC Order 2222.

The project will ensure that NYISO and the New York transmission operators have the communication protocols and procedures in place to maintain reliability as DER penetration increases, said Michael Ferrari, market design specialist in new resource integration. (See NYISO Updates Grid in Transition Work and Plan for 2022.)

The ISO has been working with the applicable member systems individually to identify transmission nodes, with those identified in the New York Control Area now totaling 115.

Transmission nodes are electrically similar facilities to which individual DER may aggregate as a DER coordinating entity aggregation (DCEA), represented by a single point identifier (PTID).

A transmission node might comprise several load nodes, which provide the most detail for NYISO system modeling and are associated with distribution stepdown transformers at facilities below the transmission level NYISO currently secures.

NYISO will present the list of transmission nodes at an ICAP meeting early in the first quarter of 2022.

NYISO and the investor-owned utilities in the state have created a framework to prohibit resources participating through an aggregator from receiving compensation for the same services as part of another program. The ISO’s Order No. 2222 compliance filing proposes to require aggregators make attestations that its DERs are not providing the same service(s) in a retail market or program.

To prevent double counting, NYISO is collaborating with the utilities to develop a document identifying retail market services that conflict with wholesale market services.

This project and current coordination efforts will continue in 2022 with a focus on facility enrollment; metering and communications infrastructure and configurations; and NYISO administrative and operational manuals, an aggregation program manual, and supporting modifications to existing manuals, Ferrari said.

One stakeholder expressed concern that the ISO was working only with the utilities on DER participation and not with aggregators, saying the one-sided approach is a missed opportunity to encourage DER participation.

The ISO responded that any utility denying participation to DER must provide detailed data to back up its rationale and lay out steps the utility will take to improve market access in that specific case.

Prohibiting Critical Infrastructure Load from DR Programs

Responding to NERC and FERC guidance, NYISO is proposing to prohibit market participants from enrolling critical infrastructure load in its demand response programs. (See Grid Faces Multiple Risks in Winter Months, NERC Warns.)

Critical infrastructure is load needed to deliver natural gas, fuel oil, and other fuels used to supply generation, and load otherwise likely to impact the supply of fuels to generators serving the New York Control Area, said Francesco Biancardi, market design specialist. It includes natural gas compressors, LNG storage facilities, fuel oil suppliers, refineries and control centers.

NERC on Oct. 6 submitted a Standard Authorization Request to address extreme cold weather grid operations, preparedness and coordination. Recommendation No. 8 states that “balancing authorities’ operating plans (for contingency reserves and to mitigate capacity and energy emergencies) are to prohibit use of critical natural gas infrastructure loads for demand response.”

In January 2021, approximately 1,071 kW of curtailment capability was offered by special case resources (SCRs) that include critical infrastructure load, according to an ISO survey of DR providers. About 175 kW of such curtailment capability was offered in July 2021.

While the total kW of demand response load is small as compared to total system MW, it is possible that curtailment of a small amount of critical infrastructure load could have a material impact on generator availability, Biancardi said. For example, curtailment of a few kW of natural gas compressor station load could cause an outage of many MW of generation, Biancardi said.

The ISO is working toward implementation before Winter 2022/23.