Negative Pricing in I-SEM? It’s already happening in SEM! (Part 1)

  I regularly get asked if there will be negative pricing in the I-SEM. It’s one of those phenomena of European markets that we often read about but which seems totally alien to us in the SEM. Negative pricing is when market prices clear at a value less than zero, meaning generators are willing to pay for their power to be consumed. In essence, it is an economic signal that there is a significant over-supply in the market (we’ll delve a bit more into how it happens in next week’s Insights article). So, will it happen in the I-SEM? If last Friday’s events are anything to go by, it’s certainly a possibility. On Friday 23rd September, both of the day-ahead runs of the SEM market for Saturday cleared at -€100/MWh during the 6:00-6:30 trading period.   This means that during this trading period a generator would be charged €100 for every megawatt generated and suppliers were actually paid for consuming power. The reason for this event becomes clear when we examine the view of system fundamentals that the market had on Friday. The day-ahead runs of the SEM solve using forecasts that are available at the time. You can see on the below chart that demand was quite low, as you would expect for a mild Saturday. Wind was forecasted to nearly completely meet that entire demand during the early morning period.   In addition, the 500 MW East-West Interconnector linking Ireland to GB was (and continues to be) on outage and the Moyle Interconnector’s export capacity is limited to 295 MW due to technical issues. That’s 705 MW less demand capacity on the system, which limits the amount of generation that can be scheduled and our capability to export during high-wind situations. Because the forecast wind was meeting the large majority of system demand, just over 200 MW of non-wind generation was required to meet the rest of the system demand. This remainder was largely made up of priority dispatch units such as CHP, biomass and hydro. All of these units are registered as price taking units in the SEM, meaning they cannot set the market price. This left SEMO with very few price making units which could actually set the market price. In the end it was actually a demand side unit which was the marginal in-merit unit during the 06:00-6:30 trading period and set the market price with their bid of -€100/MWh. As demonstrated in the chart above, wind outturn was below forecast, meaning additional price setting thermal generation was required to fill the gap in later market runs. As a result, the negative price in the 6:00-6:30 trading period did not persist in subsequent market runs, with the market price in the first ex-post run clearing at €22.08/MWh. While the final EP2 price that all participants are settled at will not contain negative prices due to over-forecast of wind for Saturday, it is worth thinking about how a similar situation would play out in the I-SEM. Unlike the SEM, trades in the I-SEM day-ahead market will be firm contractual positions, meaning in this scenario generators who traded in the day-ahead market would have committed to paying €100/MWh for that period. If you had waited to sell your power in the intraday market instead, updated wind forecasts would likely have seen market prices return to positive values, enabling you to get paid for your generation during the 6:00-6:30 trading period, rather than paying for it! The I-SEM will have multiple markets with firm pricing, so understanding system fundamentals (such as wind forecasts) and which market to trade in will play a key role in maximising asset value in the new market. Another useful insight from last weekend is the benefit of interconnection to the Irish market. At the day ahead stage, the Moyle Interconnector was scheduled to fully export 295 MW during the negative pricing period. If the additional 705 MW of interconnector capacity on outage was available and exporting, this additional demand would likely have prevented the negative prices from occurring. Furthermore, it is worth noting that the market schedules seen during the negative pricing period, which had nearly 100% of demand being met by wind, were unconstrained schedules and would not happen in real life. This is because EirGrid can only allow up to 55% of demand and exports to be met by wind (known as the “SNSP” limit) and must curtail wind generation when it goes above this level. Therefore, additional export capacity on the interconnector would also help mitigate the inevitable wind curtailment which would have to been carried out to bring wind generation below the 55% SNSP limit. In next week’s edition of Insights, we’ll take a closer look at the fundamentals that drive negative prices using examples from the GB market, where negative pricing events have increased significantly in recent years. Update: Market Prices have gone negative again for two trading periods in the day-ahead runs of Wednesday’s trading day. With EWIC on outage until early November, we could potentially be seeing more negative price events during periods of high-winds over the coming weeks.