Ireland: Regulatory Framework for BESS and Renewables – Negative Prices, Grid Charges & Markets

Negative Prices and the Renewable Energy Support Regime (RESS)

Ireland's primary support instrument for renewable electricity is the Renewable Electricity Support Scheme (RESS), established under S.I. No. 365/2020 – European Union (Renewable Energy) Regulations 2020 and S.I. No. 56/2020 – Electricity Regulation Act 1999 (Public Service Obligations) (Amendment) Order 2020 DCCAE – RESS Scheme Overview & Auction Rounds. RESS is a two-way CfD: when the Day-Ahead Market reference price falls below the participant's auction-determined strike price, the support account pays the difference; when market prices exceed the strike price, the generator pays the surplus back to consumers via the CRU-administered settlement account. This two-way design, funded through the PSO levy, provides price certainty while protecting consumers from windfalls. As of RESS 5 (September 2025), the average strike price across awarded contracts was €98.81/MWh, slightly above the RESS 4 average of €96.85/MWh DCCAE – RESS Scheme Overview & Auction Rounds.

The negative-price treatment in RESS is materially different from the German §51 EEG model, but nonetheless imposes a zero-generation payment rule during negative-price hours. Under the RESS terms applicable from RESS 3 onwards (2023), no CfD support payment is made for electricity actually generated during hours when the Day-Ahead reference price is negative. Generators that curtail output voluntarily during such hours — or that are curtailed by the system operator — can instead access the Unrealised Available Energy Compensation (UAEC) mechanism, which compensates participants at their strike price for available capacity that was not converted to generation due to oversupply or system curtailment, explicitly including periods of negative pricing Pinsent Masons – RESS 3 Structure: UAEC & Negative Price Rules. Crucially, UAEC is not available for constraint curtailment — cases where a physical network bottleneck prevents generation — which the government views as an essential locational price signal to discourage investment in congested areas Pinsent Masons – RESS 3 Structure: UAEC & Negative Price Rules. This distinction between oversupply curtailment (UAEC-eligible) and network constraint curtailment (not eligible) is a defining feature of Irish renewable project economics.

Five competitive auction rounds have been held: RESS 1 (2020, ~1.3 GW awarded), RESS 2 (2022, ~1.9 GW, predominantly solar), RESS 3 (2023, 646 MW), RESS 4 (2024, 1.3 GW), and RESS 5 (September 2025, 1.07 GW) DCCAE – RESS Scheme Overview & Auction Rounds. From December 2025, in compliance with the EU Net-Zero Industry Act, all future RESS rounds must incorporate non-price qualification criteria covering Responsible Business Conduct, Cybersecurity, and Ability to Deliver DCCAE – RESS Scheme Overview & Auction Rounds. The SNSP limit — which determines how much non-synchronous (renewable and HVDC) power the system can carry at any moment — stood at 75% as of 2025 and contributed to 17% of all wind dispatch-down that year, up from just 1% in 2024, signalling accelerating system pressure as the renewable fleet expands Climate Jargon Buster – Ireland Curtailment: 11% Wind Dispatch-Down, SNSP. Ireland received EU infringement proceedings on 26 September 2024 for failure to transpose the accelerated permitting measures of RED III (Directive (EU) 2018/2001), a compliance deficit that continues to affect project timelines European Commission – EMD Directive 2024/1711 Transposition Deadline & Infringement.

Curtailment, Dispatch-Down, and Flexibility Obligations

Ireland has one of the highest proportional curtailment rates among EU member states, driven by a combination of transmission bottlenecks, minimum generation requirements (to maintain synchronous system stability), and the SNSP limit on non-synchronous penetration. In 2025, total wind dispatch-down across the all-island system reached approximately 11.3%, comprising 6.6% constraint curtailment (network-driven) and 4.7% SNSP-driven oversupply curtailment Climate Jargon Buster – Ireland Curtailment: 11% Wind Dispatch-Down, SNSP. The annualised cost of wind constraint and curtailment reached €567 million in 2024/25, with EirGrid projecting further growth to approximately €700 million in 2025/26 — an extraordinary drag on the energy system equivalent to roughly twice Great Britain's per-MWh balancing cost on a grid one-tenth the size Energy-Storage.News – SDP-02 Go-Live, Nov 2025: BESS Wholesale Access.

EirGrid operates the SNSP limit as the primary operational instrument governing renewable penetration in real time. The limit was raised to 75% on a permanent basis — meaning up to 75% of instantaneous demand may be met by non-synchronous resources (wind, solar, HVDC imports) — and EirGrid's Operational Policy Roadmap commits to lifting this ceiling to 80% as grid-forming battery storage and synchronous condensers reduce the system's dependence on gas-fired plant for inertia and voltage support Climate Jargon Buster – Ireland Curtailment: 11% Wind Dispatch-Down, SNSP. The pathway to 95% SNSP, the level required to meet the 2030 target, underpins the entire FASS system-services reform programme described in the fourth pillar.

There is currently no statutory mandatory flexibility obligation on individual renewable generators equivalent to Germany's Redispatch 2.0 framework. Dispatch-down instructions are issued by EirGrid through the Balancing Market, where registered units submit bids that can be called in merit order. Constraint curtailment is not compensated under RESS (no UAEC, as noted above), and there is no regulatory cap on the number of curtailment hours a generator may experience in a year. However, the July 2024 Electricity Storage Policy Framework explicitly identifies curtailment reduction as a primary societal benefit of storage deployment, and the CRU's companion grid connection policy now allows co-located storage to share a single maximum export capacity allocation with its host wind or solar farm — removing a major structural barrier and enabling batteries to absorb would-be curtailed energy for later dispatch DCCAE – Electricity Storage Policy Framework for Ireland (July 2024). Hybrid project co-location (storage paired with generation at one grid connection point) is formally permitted under the revised Enduring Connection Policy (ECP-2), removing the prior requirement for separate connection points and the associated doubling of connection costs DCCAE – Electricity Storage Policy Framework for Ireland (July 2024).

Ireland faces EU infringement risk on RED III's permitting acceleration requirements — particularly the two-year deadline for co-located renewable-plus-storage repowering and the streamlined environmental assessment pathway for energy storage facilities. The European Commission's September 2024 letter of formal notice specifically cited failures in administrative simplification that affect both standalone BESS projects and hybrid developments European Commission – EMD Directive 2024/1711 Transposition Deadline & Infringement.

Network Charges for Storage: The Double-Charging Problem and 2026 Reform

The treatment of battery storage under Ireland's network tariff regime has been one of the most commercially significant regulatory questions of the 2024–2026 period. The core problem is structural: under the tariff framework that applied until 2026, battery storage units were licensed and registered as generators but were nonetheless subject to Demand Transmission Use of System (D-TUoS) charges — the same transmission fees paid by large electricity consumers — every time they charged from the grid. This created a form of double-charging: the battery paid D-TUoS on import (as if it were a consumer) and then Generator TUoS (G-TUoS) on export (as a licensed generator). The result was that D-TUoS charges added approximately €30/MWh to each charging cycle, substantially eroding the economics of wholesale arbitrage and suppressing the utilisation of operational assets ESS News – CRU Minded-To Decision on Network Charges (April 2026).

The CRU acknowledged a partial exemption as an interim measure since 2020, but independent analysis by Economic Consulting Associates — commissioned by Energy Storage Ireland and referenced in the CRU's April 2026 Minded-To Decision — found that the residual charging regime still imposed a significant barrier. The 2026 reform proposes a clean reclassification: from October 1, 2026, all standalone energy storage units and co-located hybrid systems will pay only G-TUoS charges, with D-TUoS fully disapplied ESS News – CRU Minded-To Decision on Network Charges (April 2026). Demand-TUoS will continue to apply only to storage explicitly associated with end-consumer demand applications. The CRU's consultation closed on 13 May 2026; a formal final decision is expected before the October 2026 tariff year start.

The projected system-level benefits are material. The same ECA modelling estimates that removing D-TUoS from storage will increase storage utilisation by approximately 30% and generate approximately €37 million per year in consumer savings through wholesale price compression — a self-funding reform from the consumer perspective ESS News – CRU Minded-To Decision on Network Charges (April 2026). For individual BESS projects, the impact is transformational: independent developer assessments indicate that the reform would roughly double the internal rate of return on a standard transmission-connected battery project, turning marginal developments into commercially viable investments ESS News – CRU Minded-To Decision on Network Charges (April 2026). Northern Ireland's storage assets already receive G-TUoS-only treatment, meaning the April 2026 minded-to decision also corrects a cross-border competitive distortion within the unified I-SEM.

Distribution Use of System (DUoS) charges for storage are not yet comprehensively reformed. Distribution-connected batteries face a patchwork of local network operator tariffs that do not uniformly implement the generator-treatment principle. The CRU's July 2024 Electricity Storage Policy Framework committed to a broader distribution-level charge review, but no final decision has been published as of June 2026 (to be verified against latest CRU publications). Transmission capacity charges (the fixed €/kW component of TUoS) also remain applicable and are rising significantly: the transmission revenue requirement for 2024/25 increased by approximately 38% year-on-year to €1.412 billion, driven by offshore development, European interconnection investment, and renewable integration infrastructure costs CRU – Network Charges 2024/25 Decision (TUoS Revenue Requirement).

Markets Open to a Battery in Ireland: I-SEM, DS3/FASS, and the CRM

A battery energy storage system in Ireland can now access five distinct revenue streams across the Integrated Single Electricity Market — a portfolio approach that market participants call revenue stacking. The following describes each layer as it stands in 2026, reflecting a market in active structural transition.

1. Day-Ahead Market (SEMOpx / I-SEM)
The Day-Ahead Market is a daily auction clearing at noon for energy delivery on the following day, producing a single all-island clearing price (€/MWh) for each half-hour trading period. The market is co-managed by EirGrid and SONI through their joint subsidiary SEMOpx and is integrated into the European Single Day-Ahead Coupling (SDAC) mechanism SEMO – I-SEM Market Structure (DAM, IDM, Balancing, CRM). Battery participation was technically possible since I-SEM launched in 2018 but practically restricted: until November 2025, EirGrid rarely dispatched batteries for import, creating an effective barrier to wholesale energy trading. SDP-02, which went live on November 11, 2025, removed the import restriction and enabled the TSO to dispatch batteries for both charging (import) and discharging (export) within the market framework Energy-Storage.News – SDP-02 Go-Live, Nov 2025: BESS Wholesale Access. Day-ahead spreads in Ireland average approximately €103/MWh — unusually stable regardless of wind penetration (25–70%) because the Irish generation stack jumps directly from near-zero-cost renewables to expensive gas peakers, with virtually no intermediate thermal plant to moderate prices Energy-Storage.News – SDP-02 Go-Live, Nov 2025: BESS Wholesale Access.

2. Intraday Market (SEMOpx / I-SEM)
Three intraday auctions run daily, alongside continuous intraday trading, allowing participants to adjust positions closer to real time SEMO – I-SEM Market Structure (DAM, IDM, Balancing, CRM). The intraday market is critical for batteries optimising around day-ahead forecast error and for balancing imbalance exposure. As with the day-ahead market, effective BESS intraday participation has only been operationally realised following SDP-02's November 2025 go-live.

3. Balancing Market (EirGrid Dispatch)
The Balancing Market runs in near-real-time, with EirGrid and SONI instructing registered units to deviate from their day-ahead schedules to balance the system. The TSO holds reserve capacity and issues dispatch instructions accordingly. As of 2025, Ireland operated approximately 1.4 GWh of operational BESS across 30 sites — roughly double the capacity of a year earlier — with modelling by GridBeyond suggesting that a 10 MW/2-hour battery accessing the full I-SEM suite (DA + IDM + Balancing) could achieve 12–37% higher annual revenue versus relying solely on legacy system services Energy-Storage.News – SDP-02 Go-Live, Nov 2025: BESS Wholesale Access.

4. System Services: DS3 Transitioning to FASS (DASSA)
Ireland's DS3 (Delivering a Secure, Sustainable Electricity System) programme provided fixed regulatory tariffs for a suite of frequency response and reserve products — Fast Frequency Response (FFR), Primary Operating Reserve (POR), Secondary Operating Reserve (SOR), Tertiary Operating Reserve (TOR1/TOR2), Replacement Reserve (RR), and Synchronising Unit products — that enabled the build-out of Ireland's first battery fleet EirGrid – FASS Programme: System Services Code (Dec 2025 Draft). DS3 payments have fallen by over 40% in effective value since 2022 as base tariffs were cut and multipliers reduced. The programme is being replaced by the Future Arrangements for System Services (FASS) framework, centred on competitive daily auctions via the Day-Ahead System Services Auction (DASSA). DASSA is targeted for go-live in May 2027 (longstop September 2027), following a SEM Committee decision in June 2025 to extend DS3 regulated tariffs as a transitional bridge EirGrid – FASS Programme: System Services Code (Dec 2025 Draft). In FASS/DASSA, batteries will bid into daily auctions per service per 30-minute trading period, with all-island clearing prices set per service, and secondary trading permitted up to 90 minutes before delivery. The shift from fixed tariffs to competitive auctions is expected to compress ancillary revenues further — consistent with patterns observed in Great Britain and other mature markets. EirGrid's ambition is to reach 95% SNSP via FASS, requiring new grid-forming battery inverter capability as a technical prerequisite.

5. Capacity Remuneration Mechanism (CRM / SEMO)
Ireland's Capacity Remuneration Mechanism provides multi-year capacity payments to ensure generation adequacy. Battery storage qualifies as a capacity provider and has participated in several auction rounds. The December 2024 T-4 auction for the 2028/29 delivery year cleared at approximately €149,960/MW — more than double Great Britain's equivalent T-4 clearing price — and awarded 5,942 MW of capacity agreements SEMO – T-4 2028/29 CRM Final Auction Results (Dec 2024). For batteries, de-rating factors (which reflect realistic reliability in the capacity year) have become increasingly significant: one-hour and two-hour battery systems have seen their de-rating approximately halve in recent rounds, significantly reducing their effective capacity credit. Four-hour systems being developed for the next investment cycle carry substantially higher de-rating values. Mandatory prequalification applies to all dispatchable units above 10 MW; units below that threshold may participate voluntarily SEMO – T-4 2028/29 CRM Final Auction Results (Dec 2024). The CRM's capacity auction structure (T-4 and T-1 annual auctions) ensures revenue certainty up to four years ahead, providing a bankable revenue stream alongside the increasingly competitive ancillary and wholesale markets.