Negative Pricing – European Insights (Part 2)

  In last week’s article we examined the first ever incident of negative prices occurring in the Irish Single Electricity Market and what caused it. Many have asked me if negative pricing could happen in the I-SEM, but none (perhaps myself included) could have envisaged it happening in the current SEM! Since that record-breaking day on Friday 23rd of September, we have seen two more trading days where prices have gone negative, on Thursday 29th of September and yesterday, Tuesday the 4th of October, where prices hit lows of -€59.37/MWh (EA2) and -€53.53/MWh (EP1) respectively [1]. As highlighted in last week’s article, these negative prices were largely caused by very low demand being nearly completely met by large volumes of price-taking wind generation which cannot set the market price, leaving the small remainder of demand to be met by negative-bidding priority dispatch and demand side units. While European markets differ in structure to the SEM, the fundamental causes of negative pricing in these markets (which the I-SEM will look very like) are the same. When system demand is low and there is a significant over-supply of zero marginal cost renewables, this depresses market prices close to and even less than zero if a generator is willing to pay to stay online. This could be a coal generator that does not want to incur expensive start-up costs, or even a renewable generator that gets a support payment for every megawatt of metered output. In both cases they will reflect the willingness to pay for their power to be consumed by offering power into the market at a negative price. Negative pricing events may seem extraordinary and are certainly very new to us in Ireland, they are a well-established phenomenon across continental Europe. For example, the German market introduced negative pricing functionality back in 2007. Closer to home, the GB market has been experiencing more and more negative pricing events in recent years, as demonstrated in the chart below.       The I-SEM detailed design is taking much inspiration from the GB market design; we’ll have the same power exchange operator, coupled auctions between the two markets and similar balancing market designs. Examining how negative prices occur in GB can therefore give us a better idea of what will be possible in the I-SEM. While negative prices have occurred as recently as 25th of September in GB, let’s go a bit farther back and take a look at a very interesting day on Sunday 7th August 2016. This day was particularly interesting because it holds the record for the longest single period of negative prices in GB to date. Typically, these events occur for a couple of sporadic trading periods, however on this particular Sunday the GB imbalance price dropped to -£62.50/MWh for four straight hours, from 1 to 4pm.   So during this four-hour period, a 100 MW baseload generator would have been charged over £20,000 for producing power. So what caused it? First of all, system demand was low, around 20 GW, as you would expect on a mild Sunday. On top of this, there were large volumes of renewable generation available on the system, with around 12 GW of wind and solar over the 1-4pm negative pricing period in question.   This is a considerable share of system demand to be met by renewables, and come real-time delivery, transmission constraints and the requirement to accommodate synchronous generation for system security required National Grid to constrain down large volumes of wind generation, about 2 GW system wide. Much of the 2 GW of constraint instructions issued on this Sunday were focused on wind generators in south Scotland, as you can see below, with about 1.5 GW being constrained in the region.   The south of Scotland has very a large installed capacity of wind generation, however limited capacity on the transmission grid connecting this wind hub to demand hubs in England mean that windfarms in this area are regularly constrained down. As will be the case in the I-SEM, the grid operator in GB carries out generator constraint actions by accepting decremental bids from those generators in the Balancing Market. Essentially, a generator tells the grid operator the price at which they’re willing to be turned down at. And in fact it was one such wind farm just south of Glasgow which set the negative imbalance price of -£62.50/MWh from 1-4pm. In layman’s terms, this generator told National Grid that if they wanted to turn their wind generator down, National Grid would have to pay them £62.50 for every megawatt-hour that should have been generated. National Grid accepted this bid (along with many other negative bids) and through the GB imbalance calculation, this wind generator’s decremental bid became the clearing imbalance price. So what lessons can we learn from the above example for the I-SEM? It is worth noting that the current draft I-SEM rules prohibit wind generators from submitting negative bids Balancing Market. They will, however, be able to bid at €0/MWh, which will depress the prices at which other competing generators types will bid at. To what degree the final market design will allow non-wind generators to bid at or less than €0/MWh in the various I-SEM markets will have a large impact on whether negative pricing will happen, but remains unclear at this point in time. In a purely fundamental sense, it is not hard to envisage negative prices during significant over supply periods like that witnessed on the Irish system during the first negative price in the SEM on the 24th September.  

References

[1] Source: SEMO All chart data from ElectroRoute Analytics