On Monday of last week (4th September), the Department of Communications, Climate Action and Environment released the much-anticipated consultation paper on the development of the new Renewable Electricity Support Scheme (RESS) for Ireland which will eventually be the successor to the current REFIT 2 & 3 schemes.

Community Front and Centre

As expected, there is considerable focus given to community involvement, ultimately to increase acceptance of new renewable projects. A measure to include a mandatory community investment offer for specific projects has been mooted, along with a series of grants, soft loans and potential priority grid access. How these complex mechanisms will be implemented in practice remain unclear.

Support Payment Mechanisms

The proposed support scheme itself is similar in structure to a number of RESS across Europe, such as those in GB, France and the Netherlands. The recommended approach is a technology neutral auction resulting in the awarding of a uniform-price Floating Feed-in-Premium (FFiP). All generators successful in the auction then receive the same uniform clearing price, or strike price. It is expected that there will be a number of auctions, however the frequency of these has not been specified. The length of the awarded FFiP contract will most likely be 15 years. As highlighted in the diagram below, the FFiP ensures that the supported generator earns the strike price for all power generated. Where the Reference Market Price is less than the strike price, a top-up FFiP payment is made. If RMP is greater than the strike price, the generator pays the difference back.     Consistent with other FFiP schemes around Europe, the Irish FFiP will not cover balancing costs for supported projects, instead leaving this risk with them to be managed. It has also been recommended that no premium be awarded when negative wholesale market prices occur, which could lead to an incentive for RE generators to self-curtail during such events.

Solar vs Wind?

One interesting question is how solar, offshore and other more nascent technologies will compete with the more well-established onshore wind projects in a technology neutral auction. One would expect there to be no competition. If this is the case, the consultation paper has recommended that a technology-specific auction could then be introduced. This is an approach which the Dutch have taken with their renewable support scheme, called the SDE+, which is very similar to the proposed Irish RESS. It too awards a uniform-price FFiP referenced against a strike price, but is technology specific as opposed to the proposed technology neutral Irish RESS. In 2016 there were two rounds of auctions, the first was held in Spring and had a budget of €4 billion and the second in the Autumn and had a budget of €5 billion. These auctions resulted in 3,183 projects being awarded the SDE+ subsidy, totalling 3.9 GW of RE capacity and at a cost of €9 billion. Interestingly, more solar projects were granted subsidies than wind projects under the SDE+. This was driven by the fact that wind projects must go through much more stringent planning procedures compared to solar in the Netherlands and ultimately a project cannot bid for an SDE+ subsidy without planning permission. As a result, the solar business model is becoming increasingly more competitive in the Netherlands. It is not impossible to envisage a similar scenario playing out in Ireland under the new RESS scheme given the planning challenges facing wind development projects, so this Netherlands experience should give prospective wind and solar developers food for thought.

Auctions Mean Cheaper Projects

A look at the below table of recently awarded RE prices under similar schemes in Europe could give an indication as to the future RE prices in Ireland under the proposed RESS. The trend of falling auction clearing prices continues as renewables continue to become increasingly competitive when compared with conventional energy sources.     It was announced yesterday morning that three offshore wind farms were awarded subsidies through the Contracts for Difference (CfD) allocation in GB. The clearing prices of £74.75/MWh and £57.50/MWh for delivery years 2021/22 and 2022/23 respectively are considerably less than the £92.50 price guaranteed to the Hinkley Point C nuclear plant in the UK recently, further reaffirming renewables’ increasing competitiveness. Looking at the significant downward pressure auctions place on technology costs and the ever-present political desire to minimise the cost of the PSO, it is clear to see why auctions will be the way of the future for Irish renewable energy support. ElectroRoute is active in markets across Europe from both an electricity trading and RESS project power offtake perspective and as such will be leveraging this experience to help our clients structure optimal routes to market under the new Irish RESS support scheme in the future. For those wishing to respond to the RESS consultation, which closes on 3rd November, the consultation documents can be found here.

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  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

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