Price Spikes: 8th July 2019
Price Spikes: 8th July 2019
8th July marked the second All-Island Amber Alert since project I-SEM launched in October 2018. The first Amber Alert, issued on the 24th January and covered in a previous ElectroRoute Insights blog, coincided with a price spike of €3,774/MWh. Today, we analyse the events which led to the Amber Alert and examine the resulting market behaviour.
Constraints in the North
An Amber Alert is issued when the system margin is such that a trip of the largest in-feed (generator/interconnector) would give rise to reasonable possibility of;
a) A failure to meet system demand or,
b) frequency or voltage departing significantly from normal.
The 8th’s events were analogous to those of the 24th January in that risk from local constraints in the North was mitigated by the calling on local Peaker plants which subsequently set the Balancing Market Price for the island.
System security criteria in the North requires at least three large generators to be available at all times. On Friday 5th of July Ballylumford Power Station began a major planned outage, leaving B31, B32 and B10 unavailable. B20 was also on a long-term outage. This left only three large plants available in the North – NIK1, NIK2 (Kilroot) and C30 (Coolkeeragh).
On the morning of the 6th of July, Kilroot’s NIK1 unit tripped. In order to meet system security requirements, SONI called on more expensive older units. These were cycled every 12 hours to prevent overheating and other technical issues. This, combined with the lower weekend demand, meant that an amber alert was not triggered over the weekend. The low demand also meant the more expensive units were not dispatched higher than their Lower Operating Limit (LOL) by Real-Time Dispatch (RTD), leaving them flagged out of setting the price and the potential for very large imbalance prices was reduced.
On Monday 8th, the weakness in the system as a result of these outages was exposed. The system margin (the available plant plus the emergency assistance available) was less than the jurisdictional primary spinning reserve requirement due to greater demand levels, a lack of available large NI generators and low renewable generation in NI. The Moyle interconnector was also importing at its maximum and the North-South tie line restrictions were at a maximum. SONI declared an Amber Alert at 14:24 and SEMO issued the alert to the rest of the market at 14:43. Over the duration of the Amber Alert, the imbalance price peaked at €226.52 in the 17:00-17:30 Settlement Period. The Amber Alert ceased at 19:00, and by Tuesday 9th the unplanned Kilroot outage ended and unit NIK1 returned.
The system experienced similar conditions on both Sunday and Monday – same levels of wind, interconnectors were importing and unit availability. However, the extra demand on Monday left the control room with a significantly tighter margin to work with, eventually triggering the Amber Alert.
The question is – if there was an Amber Alert for similar reasons as in January, why was the imbalance price significantly lower this time around?
It can all be explained by the bidding behaviour of the most expensive plants in the set of bids accepted by the TSO. The two most expensive plants in both cases were the older NI units. On the 24th January, the two units in question submitted incremental prices of €6,342/MWh and €5,637/MWh. Conversely on the 8th July, the same units submitted simple offer incremental prices of €500/MWh. As the imbalance price is a weighted average of the most expensive 120MW of unflagged actions taken, the 5-minute imbalance price was set notably lower in July (peak of €226.52/MWh) than in January (peak of €3,773/MWh).
In the space of six months, two Amber Alerts have occurred on the Irish system as a result of similar incidents in Northern Ireland. Undoubtably the first incident had the largest effect on imbalance prices. The introduction of Mod 09_19 which removed flags for units bound by locational constraints may have caused more ROI units to contribute to the imbalance price compared to January.
However, the occurrence of these events and price spikes are an obvious market signal that extra generation is required in Northern Ireland. On both occasions the units were setting the marginal price, and the major difference between January and July was their submitted simple bids. If the generator had desired, it could have submitted prices at the market cap price: the system clearly needed the units during the alert. To ensure market competitiveness and system stability and reliability, new generating capacity is required in the North. These pricing events provide a clear investment signal and should not be overlooked.