Summary of Recommendations

1. Extend the Support Period to 20 Years

Extend the RESS 6 CfD from 15 to 20 years for both wind and solar. This will reduces merchant tail risk and lowers the weighted average cost of capital and hopefully will produce lower bid prices and reduce the long-run PSO levy cost to consumers. DCEE/SEAI can maybe commission independent actuarial modelling to quantify the expected strike price reduction before publishing final Terms and Conditions.

Key Advantages: The lower cost of capital will flow directly to consumers through reduced strike prices and a lower PSO levy. Longer revenue certainty will guarantee financing from a broader pool of institutional lenders giving flexibility to operators. It will also signal a stable, long-term policy commitment that will reduce Ireland’s risk premium relative to competing European renewable markets.

Example: UK CfD AR7 (2025) confirms a 15→20 year extension across onshore wind, offshore wind and solar. Developer surveys consistently showed strike price reductions from this change.

2. Introduce Dynamic Capacity Reallocation Between Technology Pots

If separate wind and solar pots proceed, include a transparent mechanism for reallocating unawarded capacity between pots in the event of undersubscription. Set separate, technology-specific administrative ceiling prices (ACPs) based on current cost models. Maintain the minimum project size at 1 MW.

Key Advantages: Prevents the auction from failing to deliver its full target capacity due to pipeline imbalances between wind and solar. Since pricing of solar is at an inflection point this can have a lot of favorable consequences. Having separate ACPs can possibly ensure that neither technology is inadvertently disadvantaged by a blended ceiling. This will improve bid quality and improve the auction efficiency. Retaining the 1 MW minimum will preserve community and cooperative energy access without creating administrative fragmentation.

Example: France (2025): Technology-specific auctions operate with separate ACPs and formal inter-pot flexibility rules published in advance of each tender.

3. Differentiate Capacity Factors Per Technology Pot with Annual Review

The updated capacity factors (45% wind; 14% solar) are strongly supported. However these must be subject to a formal annual review process with updated figures published at least 3 months before any application window opens. This will prevent developers from bidding on stale assumptions. Also in general these values could change due to variation in both technology and changes in macro weather patterns caused due to climate change.

Key Advantages: Annual updates will ensure that the bid bond calibration and strike price benchmarks remain accurate (as technology performance improves) therby reducing the risk of overcompensation. Timely publication of updated factors will enable developers to submit well-priced bids, improving auction efficiency and reducing bid padding due to uncertainty. It also builds developer trust in the scheme’s technical rigour.

Example: UK DESNZ updates load factor assumptions before each Allocation Round. AR7 explicitly incorporated updated financing hurdle rates and technology cost assumptions to improve auction efficiency.

4. Phase Out UAEC Only When Hybrid Market Rules Are Operational

Do not remove the Unrealised Available Energy Compensation (UAEC) mechanism until: (a) hybrid connection rules for co-located storage are operationally live on the Irish grid; (b) MEC-sharing rules are finalised; and (c) a market-based redispatch mechanism is available. As an interim measure can we apply a graduated taper like – 100% compensation for the first 5% of curtailment, 50% for the next 5% and zero above 10%. Consider tying  removal to a specific EirGrid milestone, not a calendar date.

Key Advantages: This will help maintain project bankability during the transition period and prevent a collapse of investor confidence that could delay delivery of RESS 6 projects. This could also widen the 2030 renewables gap. The graduated taper will create economic incentive to deploy co-located storage without making it a mandatory requirement as that may not yet be technically viable at all sites. Tying removal to an EirGrid milestone rather than a date ensures the incentive structure only changes when the grid can actually absorb it.

Example: EU Commission Grids Package (December 2025): Member States instructed to design grid-friendly hybrid connection rules and remunerate flexible connections before requiring generators to bear uncapped curtailment risk.

5. Retain Deemed Output CBF with a Curtailment Adjustment Floor

The €2/MWh deemed-output basis is right provided a curtailment adjustment floor is introduced where the actual metered output falls below 75% of deemed output in a calendar year (curtailment >25%), the CBF contribution should revert to actual metered output for that year. CBF establishment before the Interim Operation Notice should be strongly supported and should include a requirement for a published local expenditure plan.

Key Advantages: Deemed output reduces the administrative burden on project operators and community fund managers, enabling faster and more predictable fund planning. The curtailment floor will ensure that projects are not penalised twice, once through lost revenue from curtailment and again through CBF contributions on energy that was never generated. This will protect project cashflows and lender covenants in high-curtailment scenarios.

Example: Scotland (Good Practice Principles for Community Benefits): Community funds should be operationally established and publicly registered before first generation, with transparent governance specifying local spend priorities.

6. Continue the requirement for  Community Benefit Funds to the requirements to publish and detail projects and impacts as per the rulebook 20205

RESS 6 should continue the good practice as outlined in the community benefit funds  rulebook ( 2025 to report annually to SEAI and on their own website, actual disbursements by category and impact.

Key Advantages: Transparency builds and maintains community acceptance of renewable energy projects, which is one of the most significant non-technical barriers to delivery in Ireland. Public accountability also encourages competitive improvement in how funds are managed, increasing the real-world impact of the mandatory €2/MWh contribution.

Precedent: Scotland (Community Energy Scotland) and Denmark (citizen co-ownership rules): Transparency and community accountability for renewable energy funds is a legal requirement, increasing public acceptance and supporting planning approvals.

7. Introduce a Simplified NZIA Compliance Pathway for Projects Under 10 MW

We could consider adopting a streamlined NZIA compliance route for projects between that are between 1 MW and 10 MW. A simplified self-declaration model against the non-price criteria rather than full audit-level evidence with post-award spot-check auditing by DCEE/SEAI covering 20% of small project awards annually. Projects 10 MW and above should continue to meet full NZIA criteria with third-party verification.

Key Advantages: Reducing the compliance burden on small and community energy projects is essential to maintaining their viability in a competitive auction as a full NZIA compliance costs could represent a disproportionate share of project capex below 10 MW. A self-declaration route with a post-award auditing will retain the integrity of the NZIA supply chain resilience objectives. This will also support the Department’s broader social and regional development objectives for the energy transition.

Precedent: Germany (InnovationAuktion 2025): Projects below 10 MW under the simplified track have reduced documentation requirements relative to large commercial projects, with proportionate post-award monitoring.

8. Add a Dedicated Grid Connection Delay Relief Event

Consider ta force majeure-style ‘Grid Connection Delay’ relief event to the RESS 6 T&Cs, separate from the existing System Operator delay relief. Review the trigger point, where EirGrid’s published connection queue timelines are exceeded by more than 6 months through no fault of the developer. The extension granted should equal the delay, capped at 18 months. The 2→3 year JR relief window extension is also supported.

Key Advantages: Grid connection delays are currently Ireland’s single largest cause of renewable project slippage, and without a dedicated relief mechanism, developers face contract default risk for circumstances entirely outside their control directly raising project risk premiums. A separate relief event prevents the existing SO delay provision from becoming overloaded and creates clear, auditable trigger conditions. This also creates a formal feedback loop to EirGrid by making queue delays financially visible at the policy level, incentivising queue management improvements.

Precedent: EU Grids Package (December 2025): Grid connection delays should not result in support scheme penalties for generators where the delay originates with the TSO or system operator.

9. Clarify Negative Pricing Treatment in CfD Settlement

The RESS 6 T&Cs should explicitly confirm that generators do not receive CfD difference payments during hours of negative market reference prices. This will be consistent with the EU Electricity Market Design Reform (2024) and the existing RESS contract terms. This should be clearly stated and not left implicit to reduce legal ambiguity and ensure correct incentives to curtail or shift output to storage.

Key Advantages: Explicit negative pricing rules will eliminate the possibility of costly legal disputes over settlement during high-renewable periods also reducing counterparty risk for both the State and project lenders. More clear rules may give economic incentive for generators to invest in storage or demand flexibility solutions to manage their own output during low-price periods leading to acceleration in the broader energy system transition. Regulatory clarity aligns Ireland’s CfD framework with EU EMD Reform requirements reducing the risk of State aid complications in future scheme reviews.

Precedent: EU EMD Reform (2024): Two-way CfDs must not remunerate generation during negative pricing periods. The European Commission has confirmed that this will apply to all new CfD contracts awarded from January 2026.