Blog: RESS 3 – The good, the bad and the ugly

09 Nov 2023

RESS 3 generated the highest cost of any renewable auction in Ireland to date, but why? Paul Blount, chairperson of Wind Energy Ireland's Net-Zero committee, identifies the problems and proposes some solutions.

It’s been a little over one month since the results of Ireland’s latest onshore wind auction were published. The auction cleared with the highest weighted average price to date despite some positive changes to the auction terms and conditions relative to previous auctions. This begs the question, why did this happen? 

Onshore auction trends

Table 1 below illustrates noteworthy trends across Ireland’s first three onshore auctions. In particular:

#1   Onshore wind has been substantially more competitive than solar in all three auctions to date even after the introduction of the evaluation correction factor in RESS 2. On average across the first three auctions, 93% of participating onshore wind MWs cleared. The equivalent figure for solar was 66%. For the avoidance of doubt, Ireland absolutely needs both technologies and the solar projects play a key role on the system! This is a simple observation in relation to the relative competitiveness.

#2 The volume of projects participating in auctions from both technologies has been reducing at a time when it needs to be increasing. The legally binding emissions reductions targets put pressure on policymakers to procure more renewables but there simply aren’t enough projects being brought through the system. This is particularly stark for onshore wind. RESS 3 had approximately a third of the volume of participating onshore wind compared with RESS 1.  

#3 Costs have been increasing. Notwithstanding significant improvements in RESS 3 terms and conditions relative to previous auctions, it was the highest cost auction to date.





Results date





Weighted average clearing price per MWh





Wind Participating (MW)




Wind Clearing (MW)





Wind % successful





Solar Participating (MW)





Solar Clearing (MW)





Solar % Successful




Table 1  Onshore RESS Auction Results 2020 - 2023

The Good:

Commercial contracting principles 101 would indicate that optimal outcomes arise when risk is allocated to the party best placed to manage it. The RESS 3 terms and conditions included key risk allocation improvements. In particular, the risk of reduced renewable output associated with system wide renewables oversupply and curtailment due to system operational constraints is no longer being allocated to RESS bidders. 

In previous auctions, these risks were assigned to bidders who had no ability to manage them. This resulted in the cost of this reduced output being internalised in bid prices with an associated risk premium. This improvement in terms and conditions will have significantly improved bid prices relative to the prices that would have been submitted without this measure. The obvious question then, is why was RESS 3 the most expensive auction to date? To understand this, we need to consider:

The Bad:

Where are all the projects?

Wind Energy Ireland data indicates that there are over 2,000 MW of wind farms in the planning system awaiting decisions and that the average timeline for planning decisions is more than 90 weeks[1]. I’m aware of projects that have been in the system for more than 3 years. It is also noteworthy that An Bord Pleanála have not granted permission for a single large onshore wind farm in the last 12 months. 

Several recent decisions have been refusals and some of these have been refused on the back of regressive local county development plans. That is to say, at a time when national and EU policy is demanding a rapid acceleration in the deployment of renewable energy projects, local councils are adopting new local county development plans that, from a spatial planning perspective, are less ambitious than their predecessors.   

This appears to be in direct contradiction of the Climate Action and Low Carbon Development Bil (Amendment) 2021 which requires all “relevant bodies” (which would include all local authorities and An Bord Pleanála) to perform their functions in a manner consistent with our climate action ambitions, to the extent practicably possible.

In summary, our planning regime is utterly broken. 

These issues are further exacerbated when you consider the sequential nature of our planning and grid connection regime.  Development companies spend many years deploying extremely high-risk development capital to secure planning for the wind farms. 

They are then required to make grid connection applications which, depending on the timing of planning grants, could take anywhere from 12 to 24 months to secure. A further planning permission is then often required for the preferred grid connection method. This can result in a fresh round of planning applications, appeals and judicial reviews. And so the cycle continues…

Older technologies are winning

Noting the 86% success rate, RESS 3 cleared just 3 onshore wind farms. Wind farm project economics are complex with many factors influencing ultimate bid prices including wind speeds, grid connection costs and local transmission capacity but one of the most significant drivers of project value is the permitted rotor diameter. 

Modern onshore turbines can have rotor diameters of 130 - 150 metres with overall tip heights of 170 – 200 metres. This allows more energy to be captured at much lower costs. As a result of the consenting issues noted above, many of the projects participating in auctions are based on older planning permissions, which in turn were based on older and more expensive turbine technologies. 

In the context of RESS 3, the 101 MW Yellow River Wind Farm was the largest project awarded a contract and had a relatively recent planning grant with turbine tip heights at the site varying from 156 to 166 metres. The second largest wind farm awarded a contract had a tip height of only 150 metres. The projects currently stuck inside our broken planning system typically have tip heights ranging from 170 – 185 metres or more, which could offer much better pricing if they were ready to compete.

The consenting regime means projects can’t get shovel-ready quickly enough and RESS terms and conditions prevent projects that aren’t shovel-ready from competing.

RESS terms and conditions are well intentioned insofar as they try to prevent speculative bidding and encourage only projects that are fully shovel-ready to participate. However, for the reasons outlined above, this is resulting in far too few projects being ready to participate. 

The country needs as many economically sensible renewable projects as possible, as fast as possible. This goal would be better supported by enabling projects to enter auctions that are taking a little more development risk. This would allow some of the consenting and commercialisation timelines to run in parallel, accelerating project delivery and increasing auction competition. The recent offshore wind auction showed that auction designs can be tailored to accommodate a more risk-on approach.

RESS 3 fixed two parts of a three-part problem

Reduced output associated with system-level oversupply, system-wide curtailment and local network constraints all represented very significant risks for bidders in RESS 1 & 2. RESS 3 addressed the first two points with the introduction of the Unused Available Energy Compensation provisions (UAEC), but bidders were still exposed to an open-ended, completely uncapped risk in relation to local network constraints. This issue was exacerbated by the SEMC decision implementing Articles 12 & 13 of the EU market regulation.

The grandfathering implications of this decision greatly amplified network constraint risks.  As such, while the decision to remove oversupply and curtailment risk is progressive, welcome and will certainly have helped to mitigate auction costs, its benefits were materially diluted as a result of this residual network constraint risk.

The Ugly:

In addition to the triggering of a shocking humanitarian crisis, Russia’s invasion of Ukraine created a significant energy cost crisis across Europe in particular. This has resulted in inflation rising at a rate that is unprecedented in several decades. This in turn has resulted in the ECB significantly increasing interest rates in an attempt to tame this inflation.

This creates a perfect storm for renewable energy projects which find themselves battling both high capital costs and the high interest rates designed to tame these costs. In the context of a “typical” onshore wind project:

  • The introduction of oversupply and curtailment compensation should reduce bid prices by something of the order of €8-13 per MWh depending on how optimistic or pessimistic bidders’ forecasts would have been. Material additional savings could be delivered if network constraint risks were also capped.
  • Appling a 7% p.a. inflation rate from 2021 to 2023, this could be expected to increase bid prices by something to the order of €10-12 per MWh. This alone would more or less wipe out the benefits of the UAEC.
  • ECB interest rates have increased from effectively 0% in July 2022 to over 4% by August 2023. This has the effect of materially increasing the cost of capital for renewable projects. A 2-3% increase in the weighted average cost of capital could increase the bid price in an auction by as much as €15-20 / MWh. 

Unfortunately, some of these factors, which are largely outside the control of the Irish Government and regulatory authorities, are having a significant negative impact on the cost of our transition to a sustainable, climate neutral economy. 

It is, however, worth noting that they are having an even greater impact on the cost of our existing fossil fueled economy, with wholesale gas prices reaching more than 10 times historic norms during the peak of the crisis. Even today, power is largely trading on wholesale markets in a band between €100 and €200 / MWh with prices predominantly set by gas. This is substantially higher than the recent high renewable auction pricing. 

So what is the answer?

  • Apply fixes to our broken consenting system.
    • Provide robust national and regional guidance to local planning authorities to ensure there is local policy support for energy infrastructure that is critical at a national level.
    • Provide ABP with the resources and skills they need to ensure accelerated and robust decision-making.
    • Ensure system operators engage meaningfully and early on potential grid connection methods for projects to allow the majority to secure planning for their connection method in parallel with the wind or solar project.
    • Ensure ESB Networks provides letters of consent to planning to allow the full end-to-end connection method to be consented.
  • Soften the RESS terms and conditions to allow projects to carry some level of development risk into the auctions. This will ultimately make auctions more competitive and will deliver more projects earlier, even with some small amount of attrition, due to projects not being fully “shovel-ready”.
  • Accelerate grid offer processes.
  • Tackle the third leg of the dispatch-down stool. RESS bidders should be offered either a nodal cap or a nodal CfD in relation to network constraints. More constrained areas should get higher caps, but this approach removes the uncertainty, reduces risks and will ultimately reduce bid prices. 

I’d be very pleased to get feedback on the above, especially from the key industry decision makers and policy makers (DECC, CRU, state agencies/academic institutions advising Government on energy policy) and other interested parties.