US grid seasonal outlook webinars: Key takeaways for NYISO and ISONE

US regional transmission organizations (RTOs) face a range of issues in fulfilling their role of ensuring power system reliability and competitively priced wholesale electricity across their jurisdictions. As the energy transition progresses, their role will only become more challenging. 

Our power and renewables short-term analysts recently presented their latest round of seasonal outlook webinars, which provide forward-looking insights for key RTOs. Fill out the form to get complimentary access to the full slide decks and webinar recordings for NYISO and ISONE, or read on for a quick summary of two key themes from the sessions.  

The impact of outage delays 

New York Independent System Operator’s (NYISO’s) 2023-2032 Comprehensive Reliability Plan (CRP) highlights growing short-term and longer-term risks to reliability on the grid. These include generator deactivations, extreme weather, uncertain demand trends due to electrification, and slow or delayed development of new generation resources.  

A key issue for NYISO is the potential for outage delays; by this we mean situations when a grid line that has been out of use is scheduled to come back online in the day-ahead model, but whose return is subsequently delayed. By looking at past events, it’s possible to identify which outages are more likely to be extended and determine the potential price impact of delays, thereby minimising negative exposure. To gain a broad view of the financial impact, we looked at both shadow prices and day-ahead real-time (DART) trades (a DART is a virtual trade bid into the day ahead market where the bidder has no intention or ability to provide supply or consume load).  

We focused on the Central East Interface and Zone K in 2023 year-to-date, as outages in these areas tend to have the biggest impact. There were a total of six different instances of delays in the return of lines after scheduled or unscheduled outages, affecting three different lines: Sprainbrook – East Garden City, Cross Sound Cable and the Marcy Series Compensator. On the majority of these occasions, the outage delays had a negative impact on DART prices for the relevant areas, ranging from -US$4.11 to -US$28.92 – a significant increase in price. On the two occasions when they didn’t, one saw a line outage start earlier than planned, while the other was a minor extension to an intraday outage that was sufficiently catered for by planned measures.  

As a result of these outages, NYISO has tended to be more conservative in its planning, with outages moved earlier, before the day-ahead model has cleared. Meanwhile, flows on the scheduled return of lines are forecast to be significantly less strong, and the timings of returns have been moved from mornings to late evening or end of day. 

Overall, this information is extremely useful in identifying which lines are more likely to be affected by delayed returns. It also indicates that long-term outages tend to be more problematic in this respect. The broader implications are that congestion and DARTs may not always capture the full picture, and that supply changes are possible as a result of outage delays. 

One last Mystic-al winter 

ISO New England (ISONE) is responsible for keeping electricity flowing across the six New England states The region’s largest fossil fuel plant, the Mystic Generating Station, is due to close in summer 2024. Its closure also puts the future of the Everett Marine Terminal LNG facility in doubt – Mystic can be powered by natural gas, but it mostly uses methane sourced from Everett, from which it takes around 80% of the output.  

Mystic’s owners have a cost-of-service-agreement (COSA) with ISONE that provides compensation for helping ensure sufficient supply. In the October New England Power Pool (NEPOOL) Participants Committee meeting the Chief Operating Officer mentioned a major change for Mystic’s final winter in service: LNG volumes under the agreement would be lower than for the previous year, at US$12-14/MMBtu, compared to the US$40-45/MMBtu for the same period last year. 

We calculate that assuming Mystic was using a US$40 LNG price and had a heat rate of seven, over the past three winters there was only one day when the facility could have just barely run ‘in merit’. In contrast, at a US$14 LNG price, Mystic would have been in merit for a total of 82 days across the three winters, against 139 days when it actually ran. It’s worth noting that during the winter of 2022-23, locational marginal prices with Mystic in the supply stack were actually higher than with it out of operation. However, the difference was strongly influenced by Mystic being in operation on the two highest-demand days. 

To summarise, lower LNG prices will mean Mystic is likely to run in merit this winter. However, fewer LNG shipments to the plant may reduce the bearish price impact across the season, with less volume on extremely high-demand days but Mystic running less often on low-demand days. Overall, Mystic isn’t likely to run more often, just at times when it’s actually needed for grid reliability. This would fulfil the goal of the COSA much more effectively than has been the case over the length of the agreement until now.  

Find out more  

Remember to fill in the form at the top of the page to get complimentary access to the seasonal outlook slide decks and webinar recordings for ISONE and NYISO. As well as exploring the above topics more fully, these include detailed reviews of the autumn period and outlooks for winter weather, demand and generation.