text: In the target years 2026, 2028 and 2035, the French NRAA reports LOLE values of 5.0, 8.3, and 15.4 hours, respectively, exceeding the corresponding ERAA LOLE values of 4.1, 3.6, and 4.0 hours. Conditions set out in ACER Decision No 01/2023.

text: The target years in the French NRAA do not start from January to December, but rather from July to June. The reason for this change is that it allows modelling a complete continuous winter, which is the period with the main risk for adequacy concerns in France.

text: Table 1: LOLE in France: ERAA vs. NRAA and the Reliability Standard (hours)

text: Target year 2026/2027 2028/2029 2030/2031 2035/2036

text: Reliability Standard 2.0 2.0 2.0 2.0 ERAA 4.1 3.6 1.8 4.0 NRAA 5.0 8.3 19.8 15.4 Source: ACER based on ERAA 2024 and French NRAA.

text: Table 2: Differences between the NRAA and ERAA: Impact on LOLE

text: Impact on LOLE # Where? What? (increase/decrease)

text: Regional scope inconclusive Scope 2 Target years inconclusive 3 Supply-demand input data decrease 4 Monte-Carlo scenarios inconclusive Inputs 5 Flow based capacity calculation for 2026/2027 increase 6 Nuclear outages patterns Increase 7 EVA approach Inconclusive 8 Risk-aversion Increase 9 Representation of Capacity Mechanisms decrease 10 Price cap modelling Increase Method 11 Cross-border exchanges Increase 12 Hydro modelling inconclusive 13 Alternative revenues decrease Source: ACER based on French NRAA.

text: Figure 1: Spatial coverage: French NRAA

text: Source: ACER based on French NRAA data.

text: Table 3: Difference between the NRAA and the ERAA: Demand projections

text: The complete public consulation was not transmitted to ACER at the time of publication of the Opinion on the French NRAA.

text: Figure 2: Difference in projected capacity in France (GW) - Nuclear and hydro excluded

text: 120 100 80 60 40 20 0 NRAA ERAA NRAA ERAA NRAA ERAA NRAA ERAA 26/27 28/29 30/31 35/36 Wind Solar CCGTs OCGTs and oil-fired peaker uits CHP and small-size plants Hard coal

text: French National Resource Adequacy Assessment 2025. 6 In this Opinion, climate years and weather scenarios are used interchangeably. Page 8 of 23

text: Figure 4: Difference in maximum import per border (MW)

text: 9000 8000 7000 6000 5000 4000 3000 2000 1000 0 FR-CH FR-IT FR-CORE FR-UK FR-ES French NRAA ERAA 2024

text: Figure 5: Nuclear availability historical trend and French NRAA projections

text: ACER notes that the French NRAA selects a subset of MC scenarios that are a combination of a weather scenario, a thermal availability pattern, and an interconnection availability pattern, while the ERAA select a subset of weather scenarios only combined with a single average availability pattern for each asset types. 8 See Annex III: Technical Annexes of the ERAA 2024 Decision. https://www.acer.europa.eu/sites/default/files/documents/Individual%20Decisions_annex/ACER_Decision_06- 2024_ERAA_2023_Annex_III.pdf

text: Figure 6: Comparison of loss of load expectation in the NRAA`s EVA and ED

text: Figure 7: Comparison of revenues in the NRAA`s EVA and ED

text: Table 4: Adequacy outcomes comparison – Reference case vs. CvaR 5% sensitivity

text: Table 5: Adequacy outcomes comparison – Reference case vs. Price cap evolution sensitivity

text: Table 6: Adequacy outcomes comparison – Reference case vs. NTC-value sensitivity

text: ACER computation based on French NRAA.

text: The discounting threshold was defined as the level of revenues perceived in the highest non-excluded MC.

text: Table 7: Summary of the sensitivities and scenario outcomes for target year 2030/2031

text: Table 8: Differences between the NRAA and ERAA: Assessment

text: # Where? What? Justified

text: Regional scope Justified Scope 2 Target years Justified 3 Supply-demand input data Justified 4 Monte-Carlo scenarios Justified Inputs 5 Flow based capacity calculation for 2026/2027 Justified 6 Nuclear outages patterns Justified 7 EVA approach Justified 8 Risk-aversion not justified 9 Representation of Capacity Mechanisms Justified 10 Price cap modelling not justified Method 11 Cross-border exchanges not justified 12 Hydro modelling Justified 13 Alternative revenues Justified

identifier: ACER Opinion No 12/2025

title: ACER Opinion 12-2025 on the French National Resource Adequacy Assessment

text: No 12/2025

text: OPINION

text: on the differences between the national resource adequacy assessment of France and the 2024 European resource adequacy assessment

text: 15 December 2025

text: A C E R O P I N I O N N O 1 2 / 2 0 2 5

text: Executive summary

text: The European Network of Transmission System Operators for Electricity (ENTSO-E) carry out the European resource adequacy assessments (ERAAs) on an annual basis. To complement ERAA, Member States may also carry out a national resource adequacy assessment (NRAA). If a NRAA identifies adequacy concerns not reflected in the European assessment, the Member State must explain the differences and submit the national assessment to ACER for opinion.

text: Key findings of the French NRAA

text: The French NRAA and ERAA 2024 are aligned in their identification of adequacy concerns for all target years except 2030. For the 2030/2031 target year, the national assessment identifies an adequacy concern, with the loss of load expectation reaching 19.8 hours. This exceeds the French reliability standard of 2 hours and reveals an adequacy concern that was not identified in ERAA 2024.

text: ACER’s assessment of differences

text: ACER identified several methodological best practices in the French NRAA. • Consideration of the contribution of capacity mechanisms in other Member States. This enables a more realistic view of the state and development of the EU electricity system. • Inclusion of ancillary service revenues. This improves the representation of investors’ business cases by accounting for an important additional revenue stream for flexible resources like batteries. • Enhanced consistency between the investment and adequacy modules. This ensures the overall coherence and robustness of the assessment. ACER finds three unjustified methodological differences between the French NRAA and ERAA 2024. • Risk aversion approach: A share of the highest revenue years is discarded and the possibility for investors to hedge part of their risk through forward markets is not considered. • Price limit increase: The repeated occurrence of price spikes on spot markets results in the increase of their price cap . The French NRAA does not replicate this dynamic leading to an underestimation of potential market revenues. • Flow-based modelling: The French NRAA applies a flow-based allocation for target year 2026/27 but uses a NTC allocation for target years 2028/29, 2030/31 and 2035/36. This does not accurately represent the French cross-border exchanges that do not rely on NTC allocation. Additional analysis conducted: To demonstrate that the adequacy concern identified for 2030/2031 would persist even without the above differences, RTE carried out additional sensitivity analyses. These analyses indicate that the adequacy concern remains, although its magnitude decreases, when the non-justified differences are removed.

text: Conclusion

text: Based on the French NRAA and the supplementary analysis provided by RTE, ACER considers the assessment reliable in identifying an adequacy concern for France for the 2030/2031 target year. ACER nonetheless suggests that RTE considers the recommendations made in this Opinion to ensure that the magnitude of the adequacy concern is more accurately captured.

text: A C E R O P I N I O N N O 1 2 / 2 0 2 5

text: 1. Background

text: Article 20 of Regulation (EU) 2019/943

text: (Electricity Regulation) requires Member States to monitor resource adequacy within their territory based on the European Resource Adequacy Assessment (ERAA). It also allows them to complement the ERAA by conducting a National Resource Adequacy Assessment (NRAA) according to Article 24 of the Electricity Regulation. Either of the two assessments can identify resource adequacy concerns, but both assessments must be based on the ERAA methodology. The adequacy concerns identified through these assessments should be in the first place addressed by eliminating regulatory distortions or market failures, and, where it does not suffice, by introducing capacity mechanisms.

text: 2 According to Article 24(3) of the Electricity Regulation, where the NRAA identifies an adequacy concern that was not identified in the ERAA, the NRAA must include reasons for the divergence between the two assessments, including details of the sensitivities used and the underlying assumptions. The Member State must publish the NRAA and submit it to ACER for opinion. ACER’s opinion assesses, on a case-by-case basis, whether the differences between the two assessments are justified. ACER primarily considers the differences identified and reasoned by the Member State in the submission, but may also identify further differences, where they have a material impact on the results.

text: 3 The national body that is responsible for the NRAA, which can be a Transmission System Operator (TSO) or a different body designated by the Member State, must take due account the ACER's opinion, and, where necessary, amend its assessment. Where it decides not to take ACER's opinion fully into account, it must publish a report with detailed reasons.

text: 4 The latest ERAA (ERAA 2024) was approved by the ACER Decision on 11 August 2025. To complement it, the Directorate General for Energy and Climate of France (the French Ministry) requested the French TSO, Reseau de Transport d’Electricite (RTE), to conduct a National Resource Adequacy Assessment (French NRAA or NRAA).

text: 5 On 27 October 2025, the French Ministry submitted its NRAA to ACER. The submission includes reasons for its divergence from the ERAA 2024, as well as the details of the sensitivities used and the underlying assumptions.

text: 6 This Opinion follows the submission of the French NRAA and evaluates whether the differences between the French NRAA and the ERAA 2024 are justified.

text: 7 This Opinion is addressed to the French Ministry and issued in accordance with

text: Article 9(2) of Regulation (EU) 2019/942

text: and Article 24(3) of the Electricity Regulation.

text: 2. Summary of the French NRAA

text: 8 The aim of the French NRAA is to complement the ERAA 2024 by adopting different input assumptions and modelling approaches that more adequately reflect the French electricity system based on historical observations and recent power system evolutions.

text: 9 The French NRAA and ERAA both models 4 target years (2026, 2028, 2030 and 2035). While the French NRAA shows an adequacy concern in all target years, ERAA 2024 shows adequacy concerns for target years 2026, 2028 and 2035 but not for 2030. The results of the central A C E R O P I N I O N N O 1 2 / 2 0 2 5 scenario of the French NRAA hence diverge from ERAA 2024 for the target year 2030, where the estimated LOLE is much higher than in ERAA 2024. This is summarised in Table 1.

text: 10 This divergence in the LOLE results is due to differences in the modelling choices and assumptions between the French NRAA and the ERAA 2024. These differences are discussed and assessed by ACER in the following section.

text: 3. ACER’s assessment

text: 11 ACER welcomes the French NRAA and considers it a well-developed assessment of the French electricity system, enriched with relevant methodological details. The report provides a clear description of the modelling assumptions, the differences to ERAA 2024, and the adequacy results.

text: 12 The differences between the French NRAA and the ERAA 2024 falls into three categories: (i) scope, (ii) inputs, and (iii) method. Each difference is listed in Table 2, along with its impact on LOLE. A detailed description of each difference is provided later in this section. A C E R O P I N I O N N O 1 2 / 2 0 2 5

text: 13 The French NRAA is based on a single modelling tool that differs from the one used in the ERAA. While the ERAA relies on the Plexos model, the French NRAA is developed using the Antares tool. As a result, modelling choices could differ between the two assessments. ACER considers that Antares is an appropriate tool to run a resource adequacy assessment.

text: 3.1. Scope

text: Difference #1 Regional scope (see Section 2.2.2 in the NRAA)

text: 14 Description: An NRAA is an assessment with a regional scope compared to the pan-European ERAA. In the French NRAA, coverage is highlighted in Figure 1: France in dark green and the other modelled countries in green, some of them being divided into several bidding zones (Denmark, Italy, Norway, Sweden, United Kingdom).

text: 15 Relevance: Reducing the geographical scope may affect the adequacy results because it determines the extent to which cross-border exchanges are taken into account. If the geographical scope is too narrow, the assessment may fail to capture the contribution of neighbouring systems during scarcity hours and therefore underestimate the level of support available to the French electricity system.

text: 16 Assessment: The reduced spatial coverage applied in the French NRAA includes the relevant set of countries, namely France’s direct neighbours as well as other bidding zones that may significantly influence France’s cross-border exchanges. ACER considers that this regional scope is consistent with

text: Article 24 of Regulation (EU) 2019/943

text: and therefore that the difference compared with ERAA is justified. Difference #2 Target years (see Section 2.1.2 in the NRAA)

text: 17 Description: The French NRAA considers overlapping years (2026/27, 2028/29, 2030/31, and 2035/36) -modelled from July of year N to June of year N+1. By contrast, ERAA uses calendar years (2026, 2028, 2030, and 2035), modelled from January to December.

text: 18 Relevance: Using overlapping years centres the simulation on the winter period, which corresponds to the period during which scarcity risks are most likely to materialise in France.

text: 19 Assessment: ACER considers that centring the assessment horizons around the winter period better reflects the thermo-sensitivity of the French power system and enables a more accurate representation of seasonal constraints. This approach leads to a more realistic assessment of scarcity periods in France and is therefore considered justified. A C E R O P I N I O N N O 1 2 / 2 0 2 5

text: 3.2. Input

text: Difference #3 Demand and supply hypothesis (see Section 3.2 in the NRAA)

text: 20 Description: The French NRAA applies lower demand trajectories than ERAA 2024, leading to differences in both demand levels and demand profiles. These assumptions reflect downward revisions in expected electrification, notably in the industrial and hydrogen sectors.

text: 21 The generation capacity assumptions used in the French NRAA are broadly consistent with those of ERAA 2024, with slight upward adjustments for solar capacity, downward adjustments for offshore wind capacity, and a partial phase-out of oil and gas units. These adjustments were introduced either to account for the different temporal structure of the target years modelled (see Difference 2) or to reflect the most recent information collected during the public consultation carried out for the French NRAA .

text: 22 Relevance: Demand projections in the French NRAA are lower than those in ERAA 2024 for all target years, with the greatest difference being 34 TWh in 2035 (see Table 3). As a result, demand-supply equilibrium is expected to be met more easily. TWh French NRAA ERAA 2024 Target years 26/27 28/29 30/31 35/36 2026 2028 2030 2035 Domestic 455 479 508 583 483 513 535 617 consumption

text: 23 At the same time, the French NRAA adopts higher supply capacity assumptions than ERAA 2024. It projects higher level of solar capacities, although the gap tends to close for later target years (from +32.5% in 2026/2027 to +4.5% in 2035/2036). The same occur for wind capacities, with assumptions nearly converging in later target years (from +7.8% in 2026/2027 to -0.4%% in 2035/2036). In that case, the slightly lower wind offshore projections are offset by greater wind onshore capacities. Regarding fossil thermal capacities, CCGTs show a slight phase-out from 6.7 GW to 5.9 GW contrary to ERAA 2024 which assumes a constant 6.6 GW capacity. The French NRAA also adopts less conservative assumption for other fossil generation. There is no difference concerning nuclear and hydro inputs capacities. Overall, the French NRAA assumes higher input capacities, as illustrated in Figure 2. A C E R O P I N I O N N O 1 2 / 2 0 2 5

text: 24 Assessment: The French NRAA combines lower demand and higher supply than ERAA 2024. These differences are not expected to lead to an overestimation of adequacy concerns. ACER considers the differences in demand and supply assumptions are justified as they reflect the latest updates of the evolution of the French power system including input from recent public consultation conducted for the purpose of the French NRAA . Difference #4 Monte-Carlo scenarios (see Section 2.2.3 in the NRAA)

text: 25 Description: The French NRAA uses 200 climate years representative of projected climate conditions as of 2025. The climate database is provided by Météo-France, the French meteorological public body. These are combined with 60 thermal power plant and 60 HVDC power line availability patterns, resulting in 1,000 Monte Carlo scenarios. All 1,000 scenarios are used in the Economic Dispatch (ED) module, while a subset of 20 MC scenarios is selected for the Economic Viability Assessment (EVA) module.

text: 26 On the other hand, ERAA 2024 relies on 36 weather scenarios representing future climate conditions and issued from the Pan-European Climate Database (PECD) 4.1. These weather scenarios are combined with 15 thermal and interconnections availability patterns, yielding 540 Monte Carlo scenarios. For the EVA, only a subset of 3 weather scenarios and an average of all outage patterns are used.

text: 27 Relevance: Climate years/weather scenarios capture the inherent uncertainty related to probabilistic events of weather and impact the hourly demand and generation profiles as well as their seasonality. Considering the French power system’s thermo-sensibility, the underlying assumptions of climate years/weather scenarios have a substantial impact on adequacy results.

text: 28 Assessment: The large number of climate years considered in the French NRAA both in the EVA and the ED allow for a broader probabilistic representation of adequacy situations of the French power system. It is expected to enhance the robustness of the assessment and is therefore justified. A C E R O P I N I O N N O 1 2 / 2 0 2 5 Difference #5 FB domains for target year 2026/27 (see Section 3.2.6 in the NRAA)

text: 29 Description: RTE set the flow-based (FB) constraints for the 2026/27 target year using the Porygon methodology. This results in FB domains that differ from those applied in ERAA 2024 but are more closely aligned with the inputs of ERAA 2025. In practice, this leads to lower theoretical maximum import and export net positions for France. RTE provided comparison for the winter domains of the 2026/27 target year (3 in ERAA vs. 2 the French NRAA) as shown in Figure 3. Figure 3: Differences in theoretical maximum import and export net position for France

text: 30 In addition, RTE compared the maximum import observed during scarcity hours for each French border in the French NRAA with those of ERAA 2024, as shown in Figure 4. The comparison shows that, despite the smaller FB domains used in the French NRAA, the maximum energy imported occurring in the French NRAA remain broadly comparable with the one in the ERAA 2024 (maximum imports being 5.2% smaller across all borders).

text: 31 Relevance: The size of FB domains directly determines the cross-border exchange capability available to France. Smaller domains can underestimate import capability during periods of system stress, hence leading to higher adequacy risk outcome. Likewise, they may underestimate export capability, reducing the economic viability of domestic capacity and ultimately contributing to increased adequacy concerns.

text: 32 Assessment: Given that the maximum import capacity during scarcity hours is consistent with the values simulated in ERAA 2024, ACER considers that the French NRAA approach provides a Page 9 of 23 A C E R O P I N I O N N O 1 2 / 2 0 2 5 realistic representation of France’s cross-border exchanges in scarcity hours. The resulting difference in the FB domain is therefore considered justified. Difference #6 Nuclear availability patterns (see Section 2.3.1.4 in the NRAA)

text: 33 Description: Although both assessments consider the same 63 GW French nuclear fleet capacity (existing reactors and the Flamanville EPR) for all target years, the French NRAA assumes broader availability patterns compared to the ERAA. Notably, the French NRAA considers 60 nuclear availability patterns, while the ERAA only considers one. Such assumption aims to reflect uncertainties linked to planned and forced outages, such as maintenance outage durations and delays. This results in higher dispersion of annual nuclear potential generation (ranging from 290 TWh to 450 TWh potential generation pre-simulation).

text: 34 Additionally, and following Electricite de France’s (EDF) revision of nuclear availability assumption, the average nuclear winter availability, fixed at 50 GW in the ERAA, has been revised up to 51 GW for target years 2026/2027 and 2028/2029, and up until 52 GW for later target years. Overall, the updated nuclear availability profiles are consistent with historical trends as RTE illustrated in Figure 5, as well as in France’s Multi Annual Energy Plan.

text: 35 Relevance: Nuclear generation represents a substantial share of power supply in France. Small changes in assumed availability significantly affect adequacy margins, import dependency, and economic viability of resources. In that sense, considering a greater dispersion of nuclear availability patterns is expected to increase the average estimated LOLE, as lower availability patterns are expected to lead to more scarcity situations. The impact on the economic viability of non-nuclear resources less predictable, considering that some availability patterns used in the French NRAA result in greater nuclear generation than in the ERAA.

text: 36 Assessment: The French NRAA improves the representation of nuclear operational constraints such as uncertainties regarding the duration of outages and updates the availability projection using the latest official information. These differences compared to ERAA 2024 enhance the assessment’s robustness; ACER, therefore, considers the difference justified. A C E R O P I N I O N N O 1 2 / 2 0 2 5

text: 3.3. Method

text: Difference #7 EVA approach (see Section 2.2.6. in the NRAA)

text: 37 Description: The French NRAA EVA evaluates the economic viability of resources using a revenue-based iterative modelling approach applied to capacities located in France. By contrast, ERAA applies a system-wide cost-minimisation approach, in which the optimal capacity mix is determined by minimising total investment and operational costs. To perform the EVA, RTE first runs an Economic Dispatch (ED) with the initial capacity mix over 1 000 Monte Carlo (MC) scenarios. On this basis, a scoring algorithm is applied to select a subset of 20 MC scenarios, which is broader than the subset of 3 weather scenarios used in ERAA . This subset is then used to assess whether market entry candidates, existing, and refurbished thermal, DSR, and batteries units would be economically viable without a capacity mechanism.

text: 38 The scoring algorithm of the French NRAA is based on 3 criteria capturing scarcity events and revenues: the average LOLE, the average yearly revenues of an OCGT, and the average yearly revenues of an OCGT considering risk aversion (see Difference 7). The subset of 20 MC scenarios that performs best against these criteria across all target years is retained for the EVA. At the start of each iteration, each unit’s Net Present Value (NPV) is computed based on simulated revenues across all target years. In case of positive NPV, the asset is evaluated as economically viable, hence enters or remains in the market. Inversely, assets with negative NPV decommission or do not enter the market. Then, starting from the first target year, the least profitable existing capacity is removed from the capacity mix, while the most profitable entry candidate is added. This process is iterated until no further decision arises. Then, the same evaluation is done for the next target year, until all target years are evaluated and a new iteration is launched. The iterative process continues until a stable, viable, capacity mix composition is reached.

text: 39 In ERAA, the EVA is carried out in a single optimisation step using a cost-minimisation objective. Similarly to the French NRAA, the ERAA does perform the EVA with a reduced number of weather scenarios, selecting a subset of 3 weather scenarios out of the 36 of the full set and an average outage pattern. The selection algorithm is based on the Wasserstein distance and the criterion used is CCGT and OCGT net revenues. Based on this selected subset, the overall cost of the system is minimized, starting from an initial capacity mix and adjusting technologies’ capacities and operational dispatch considering their commissioning/decommissioning/mothballing/life-extension potential. The EVA stops when the cost-minimizing capacity mix is reached. To calculate the adequacy metrics, the ED is run with this resulting optimal, cost-minimizing capacity mix on the full set of weather scenarios.

text: 40 Because the French NRAA uses the same dispatch model in both the ED and the EVA and relies on a larger subset of 20 Monte Carlo scenarios explicitly selected to reflect scarcity events and revenues, the EVA provides a more accurate representation of the potential revenues available to investors. This, in turn, results in a high degree of consistency between EVA and ED outcomes in the French NRAA, as illustrated in Figure 6 and Figure 7. Consequently, the French NRAA EVA approach achieves closer alignment between the EVA and ED modules than ERAA 2024 both in terms of adequacy metrics and revenue outcomes. A C E R O P I N I O N N O 1 2 / 2 0 2 5

text: 41 Relevance: Consistency between the EVA and ED is essential to ensure that the investment decisions modelled in the EVA are based on a realistic representation of the revenues ultimately observed in the ED. If the EVA is run on an insufficient or non-representative subset of MC scenarios, it may misrepresent scarcity patterns and revenues, thereby biasing investment signals and, ultimately, adequacy outcomes.

text: 42 Assessment: ACER considers that the iterative, revenue-based EVA approach used in the French NRAA complies with Article 6(2) of the ERAA methodology and constitutes good practice in line with the European Commission’s report on the assessment of possibilities of streamlining and simplifying the process of applying a capacity mechanism. The computational efficiency of the iterative revenue-based design makes it possible to use a larger, representative subset of Monte Carlo scenarios and to avoid additional simplifications of the dispatch module in the EVA, thereby enhancing the internal consistency between the two modules. This is confirmed by the comparison provided by RTE, which shows a strong alignment of LOLE and revenue outcomes between the EVA subset and the full Monte Carlo set (see Figure 6 and Figure 7). ACER therefore considers that the difference in the EVA approach is a methodological improvement compared to ERAA 2024 and, therefore, justified. Difference #8 Risk-aversion approach (see Section 2.3.4. in the NRAA)

text: 43 Description: In the French NRAA, risk aversion is modelled endogenously through an adjustment applied within the net present value calculation of assets when assessing their economic viability (See Difference 6). Instead of determining the net present value on the basis of the full expected revenue across all Monte Carlo scenarios, the French NRAA applies risk-adjusted revenue A C E R O P I N I O N N O 1 2 / 2 0 2 5 directly. For each target year, this measure is derived by excluding the 10 percent of Monte Carlo scenarios with the highest revenues and calculating the expected revenue over the remaining MC scenarios.

text: 44 Description: When performing the EVA, the French NRAA models investor risk aversion using a yearly Conditional Value at Risk with 10 % parameter (CvaR 10%) approach. The method consists of computing annual revenues for each MC years performed in the EVA, and excluding the 10% with the highest average revenues when computing the Net Present Value (NPV) of assessed capacities.

text: 45 This approach does not take into account the possibility for investors to hedge part of their revenue risk in forward markets. It results from the systematic exclusion of the highest revenue MC scenarios in all target years, irrespective of the availability of forward market instruments that could partially mitigate revenue volatility. RTE justifies this approach on the grounds that forward products lack liquidity beyond Y+3, and across all horizons for peak products. Hence, the liquidity of forward products limits their ability to provide meaningful hedging opportunities for existing peaking and all new technologies and therefore limits investors’ reliance on such instruments when evaluating investments.

text: 46 ERAA 2024 represents investor risk aversion through an increase in the Weighted Average Cost of Capital (WACC) via an additional technology-specific hurdle premium. The model first calculates expected revenues under risk-neutral assumptions and then applies the WACC together with the hurdle premium. This approach reflects standard industry practice and is explicitly recognized in the European Commission’s report on the assessment of possibilities of streamlining and simplifying the process of applying a capacity mechanism. According to the ENTSO-E survey conducted in 2025, 20 out of 21 respondents reported using a hurdle-premiumbased approach to account for risk aversion, and half indicated that they also use additional riskaversion tools alongside hurdles rates.

text: 47 The technology-specific hurdle premiums also allow ERAA to implicitly take forward markets into account. These premiums are calibrated to reflect typical investor expectations, including the extent to which forward markets mitigate revenue volatility. For example, investment in new thermal units is evaluated using a higher premium than decommissioning decisions, as a smaller share of risks can be hedged at the time of investment due to the longer time horizon. This approach is consistent with the methodology described in Boudt et al. , which forms the basis for the calculation of hurdle premiums in ERAA. Unlike the approach used in the French NRAA, the hurdle-premium methodology in ERAA does not discard the highest-revenue Monte Carlo years but instead discounts their contribution through the application of a WACC and technologyspecific hurdle premiums.

text: 48 To justify its risk-aversion assumptions, the French TSO provided the responses to question 16 of its public consultation (“Does the hypothesis of risk aversion in anticipating energy market revenues appear grounded to you? If so, do you support its modelling through the use of Conditional Value-at-Risk with a 90% threshold?”). The four stakeholders that provided relevant answers are physical asset owners that may invest in new capacities. They indicate that investors and financiers tend to exclude uncertain, exceptional revenue episodes such as price spikes from their business cases, citing limited forward market liquidity, regulatory interventions and hedging practices. Respondents generally support using a CVaR approach to operationalize this risk aversion, with the 10 percent parameter serving as a reasonable reference, while also noting that sensitivity analyses on the level of this parameter would be advisable.

text: 49 RTE further justifies its treatment of forward markets by referring to one respondent’s feedback that underlines the limited risk-mitigation opportunities provided by forward products. According to this stakeholder, low liquidity, especially beyond Y+4, does not offer sufficient hedging opportunities for future investment revenues. In addition, the respondent argues that forward A C E R O P I N I O N N O 1 2 / 2 0 2 5 market hedging implies a significant revenue discount, limiting the ability to benefit from scarcityrelated revenues. RTE considers that this view is consistent with the one of the French NRA, for example in their quarterly market monitoring report that highlights the lack of liquidity of forward products beyond Y+3.

text: 50 Relevance: The assumed level of risk aversion directly influences investment incentives. Higher risk aversion reduces estimated revenues and may discourage investment, which can result in higher LOLE outcomes. At the same time, forward markets reduce investor exposure to revenue volatility. Where hedging is realistically available and forward markets are sufficiently liquid for some of the assets evaluated, not reflecting this possibility leads to an overestimation of risk aversion, a reduction in the level of economically viable capacity and, ultimately, less realistic adequacy outcomes. In this context, incorporating technology-specific parameters, as done through technology-specific hurdles premiums, is recommended, as revenues patterns and exposure to market uncertainty differ significantly across technologies and may shape how investors assess risk.

text: 51 Assessment (forward markets): ACER considers that the French NRAA provides evidence that not all risks faced by investors can be hedged through forward markets. However, ACER also considers that the portion of risk that can be hedged should nevertheless be taken into account. For this reason, ACER finds that the French NRAA’s assumption that investors do not hedge any risk through forward markets is not justified. ACER recommends that future editions of the French NRAA explicitly consider the possibility for investors to hedge part of their risk through forward markets.

text: 52 Assessment (treatment of high-revenue years): ACER finds the reasoning in the French NRAA (that investors are unlikely to base their investment decisions on revenues arising mainly from Monte Carlo scenarios that are very unlikely to occur) to be reasonable. However, ACER considers the assumption that investors completely disregard such potential revenues to be too restrictive. Exceptional revenues should, at least, be partially considered when modelling investment decisions, as is the case when hurdle premiums are used in ERAA, where highrevenue years are discounted rather than discarded. For this reason, ACER considers that discounting rather than fully excluding the highest revenue MC scenarios is more realistic. ACER therefore recommends that future editions of the French NRAA apply an appropriate discount to the highest-revenue MC scenarios rather than removing them entirely from the calculation of expected revenues.

text: 53 To quantify the impact of the CvaR and reflect the hedging possibility of forward markets, RTE provided a sensitivity analysis using a lower risk aversion parameter. Although RTE argues that the CVaR 5% represent an extreme case of hedging possibilities since it is applied to all capacities and all horizons whereas liquidity of forward products is limited, this sensitivity with less risk averse actors could represent some forward hedging possibilities. Results for 2030/2031 are shown in Table 4: Adequacy outcomes comparison – Reference case vs. CvaR 5% sensitivity. LOLE (h) EENS (GWh) A C E R O P I N I O N N O 1 2 / 2 0 2 5 Reference case – CVaR 19.8 73.8 10% Sensitivity – CvaR 5% 12.5 41.1

text: 54 The sensitivity confirms that lower risk aversion improves adequacy (LOLE falls from 19.8h to 12.5h and EENS from 73.8 GWh to 41.1 GWh. This highlights the importance of the calibration of risk aversion parameters and the proper consideration of forward markets.

text: 55 Nevertheless, as the adequacy concerns remain even under the sensitivity, ACER concludes that this unjustified risk aversion choice, when considered in isolation, does not undermine the overall validity of the French NRAA results.

text: 56 Recommendation: ACER recommends that future French NRAA editions refine the current risk aversion approach using the discounting method as explained above. Difference #9 With-CM approach (see Section 2.3.3. in the NRAA)

text: 57 Description: In the French NRAA, the EVA is performed only for France. For all other Member States, capacity levels are adjusted exogenously so that, where a reliability standard is defined, LOLE levels are equal to that standard. This leads to capacity addition in Member States where, pre-adjustment, the reliability standard is not met and capacity reduction in those where it is exceeded. For the target year 2030/2031, the French NRAA thus identifies around 22 GW additional capacity in Germany, while 15 GW are considered in excess in Italy and 16 GW in Spain.

text: 58 In contrast, ERAA models investment and decommissioning decisions endogenously across all Member States. Investment decisions are based on a pan-European economic viability assessment, allowing capacity to be added or removed wherever it is economically justified.

text: 59 Relevance: Policy choices in other Member States directly influence France’s adequacy outcomes through cross-border exchanges. If capacity is underestimated in a neighboring Member State, its contribution to France’s adequacy will also be underestimated. Conversely, if capacity is overestimated, its contribution will also be overestimated.

text: 60 Assessment:

text: Article 24 of Regulation (EU) 2019/943

text: requires the NRAA to have a regional scope. This means that the NRAA shall consider the contribution of other Member States through crossborder exchanges. ACER considers that the approach of assuming that other Member States are at their reliability standard is an appropriate approach for a national assessment, as it provides a transparent and realistic representation of their contribution. By restricting endogenous investment decisions to France while externally constraining capacities in neighbouring Member States to their reliability standard, the French NRAA is, in ACER’s view, consistent with the regional scope requirement.

text: 61 In terms of impact, ACER observes that in ERAA 2024, several neighbouring Member States, particularly in the CORE region, exhibit LOLE levels above their reliability standards, indicating undercapacity. As a results, the risk that the French NRAA underestimates the contribution of cross-border exchanges to France’s adequacy is limited.

text: 62 Given the above, ACER considers the French NRAA’s approach where neighbouring Member States’s capacities are adjusted to exactly meet their respective reliability standards to be appropriate. This approach provides a balanced and plausible estimation of cross-border contributions to adequacy and is hence considered justified. A C E R O P I N I O N N O 1 2 / 2 0 2 5

text: 63 Furthermore, ACER notes that it is good practice to dimension capacity mechanisms under the assumption that other Member States will, at a minimum, meet their respective reliability standards. This approach helps to mitigate the risk of over-procurement, where multiple Member States might contract capacity to address the same (regional) adequacy concerns in an uncoordinated manner.

text: 64 Recommendation: For dimensioning a potential capacity mechanism, ACER recommends maintaining the assumption that all other Member States meet their respective reliability standards. Difference #10 Price cap modelling (see Section 3.3.4.4. in the NRAA)

text: 65 Description: The French NRAA assumes a constant electricity market price cap of 4,000 EUR/MWh across all target years. In contrast, ERAA includes the possibility of increases in the price cap, based on the expected evolution of price limits derived from the previous ERAA cycle. ERAA 2024 therefore applies rising caps: 4,500 EUR/MWh in 2026, 5,000 EUR/MWh in 2028, 6,000 EUR/MWh in 2030, and 6,500 EUR/MWh in 2035.

text: 66 Relevance: A lower price cap reduces the potential scarcity revenues, which may discourage investment, thus increasing adequacy concerns. For example, in 2035, the French NRAA assumes a cap of 4,000 EUR/MWh, while ERAA assumes 6,500 EUR/MWh. Under identical scarcity conditions, this implies that scarcity revenues are limited by a cap that is 38.5% lower in the French NRAA.

text: 67 Assessment: The French NRAA justifies its static price limit assumption by stating that market participants may not trust future increases. To support this, RTE refers to the public consultation conducted for the purpose of the French NRAA, in which one respondent argued that there is a risk of regulatory intervention via a possible revision of the methodology on price cap increase. RTE also points out to the ENTSO-E survey in which only one respondent indicated assuming future developments in the price cap over time.

text: 68 ACER notes that the non-consideration of price cap increases is inconsistent with past development, as the market price cap has already risen from 3,000 to 4,000 EUR/MWh. Thus, an assumption that excludes any future increase is not in line with former observations.

text: 69 In addition,

text: Article 10(2) of Regulation (EU) 2019/943

text: requires a transparent mechanism to adjust bidding limits when the existing limits are expected to be reached. This provision makes clear that price limits are intended to evolve so as not to restrict free price formation. Assuming a fixed cap over the entire horizon effectively ignores this legally foreseen adjustment mechanism.

text: 70 As the French NRAA’s assumption of a fixed price cap does not align with the regulatory framework or with past observed market developments, ACER considers that applying it is not justified.

text: 71 To quantify the impact of the difference, RTE provided a sensitivity analysis using the ERAA 2024 price cap trajectory. Results for 2030/2031 are shown in Table 5. LOLE (h) EENS (GWh) Reference case – Price cap 19.8 73.8 = 4000 EUR/MWh A C E R O P I N I O N N O 1 2 / 2 0 2 5 Sensitivity – ERAA 2024 16.9 60.5 price caps

text: 72 The sensitivity confirms that higher, evolving price caps improve adequacy (LOLE falls from 19.8h to 16.9h and EENS from 73.8 GWh to 60.5 GWh). This highlights the importance of correctly reflecting the regulatory framework and observed market developments.

text: 73 Nevertheless, as adequacy concerns remain even under the sensitivity, ACER concludes that this unjustified modelling choice, when considered in isolation, does not undermine the overall validity of the French NRAA results.

text: 74 Recommendation: ACER recommends that future French NRAA editions consider the price cap mechanism in the model. Difference #11 Cross-border exchanges (see Section 2.3.2. in the NRAA)

text: 75 Description: The French NRAA applies a flow-based approach for the target year 2026/2027 but reverts to a net transfer capacity (NTC) approach for the 2028/2029, 2030/2031 and 2035/2036. RTE justified this by the limited visibility on future Critical Network Elements and Contingencies (CNECs) for these later horizons and by stating that reusing 2026 flow-based domains would be overly conservative and not reflective of expected grid developments.

text: 76 In contrast, ERAA 2024 uses a flow-based methodology for all target years. This represents an evolution from ERAA 2023, which relied on a hybrid approach combining 2025 flow-based domains with ATC-based extensions for later horizons.

text: 77 Relevance: Flow-based market coupling generally allows more efficient cross-border capacity allocation than an NTC approach. Using NTCs may therefore underestimate the contribution of neighbouring Member States during scarcity periods. This may not lead to a realistic estimation of adequacy concerns and inflate the volume required to meet the reliability standard, thereby increasing the risk of over-procurement under a capacity mechanism.

text: 78 Assessment: The Electricity Regulation requires the use of flow-based capacity calculation. The French NRAA is therefore not compliant with this requirement for the target years modelled using NTCs, and ACER considers this deviation not justified.

text: 79 To quantify the impact of the difference, RTE provided additional elements for 2030/2031, the only target year with diverging LOLE outcomes compared to ERAA 2024: • RTE compared maximum imports from the CORE region: 7.6 GW in the French NRAA versus 10.9 GW in ERAA 2024. The French NRAA maximum import value corresponds to the historical NTC value established for BE-FR and DE-FR borders before the before the introduction of flow-based market coupling, augmented by capacity increases from new projects. This comparison thus indicates a difference of around 3 GW in import capacity. • To complement the comparison, RTE performed a sensitivity analysis adding 3 GW of additional import capacity from CORE (1.5 GW on BE-FR, 1.5 GW on DE-FR), bringing import capacity levels closer to the one of ERAA 2024. As shown in Table 6, the impact on adequacy outcomes is limited, with LOLE decreasing by 0.2h for target year 2030/2031. French NRAA Reference case Sensitivity – NTC values A C E R O P I N I O N N O 1 2 / 2 0 2 5 LOLE (h) 19.8 19.6

text: 80 These results indicate that, although the NTC assumption restricts cross-border exchanges compared to ERAA 2024, its quantified impact on French adequacy outcomes in 2030/2031 remain limited. ACER, therefore, concludes that this unjustified modelling choice, when considered in isolation, does not undermine the overall validity of the French NRAA results.

text: 81 Recommendation: Future French NRAA editions adopt a flow-based approach for all target years to ensure compliance with the Electricity Regulation and consistency with the ERAA methodology. This recommendation also applies to the dimensioning and the Maximum Entry Capacity (MEC) calculation for any potential capacity mechanism. ACER considers it essential that capacity-mechanism procurement relies on flow-based modelling. As a mitigation, until flowbased domains can be implemented for all target years, ACER considers that, at least for the closest-to-delivery auction, both the MEC and the volume to be procured should be computed using flow-based modelling. Difference #12 Hydro (see Section 2.3.1.3. in the NRAA)

text: 82 Description: The French NRAA, like ERAA 2024, models hydropower facilities based on their type, installed capacity, and technical and economic parameters. However, it introduces a threestep heuristic reservoir management approach to better estimate the weekly available hydropower generation within the Antares optimisation window.

text: 83 This heuristic is based on input inflow data and the shape of the residual load as follows: • First, a monthly pre-allocation is performed in proportion to residual load to reflect the seasonality of the French power system. • Second, daily generation targets are derived from the monthly pre-allocation, accounting for reservoir constraints, and then aggregated into weekly generation targets. • Third, hydropower dispatch is optimized at the hourly level in the ED based on costminimization, subject to the weekly generation constraints determined in the second step. The application of this heuristic constrains hydropower generation profiles so that they more closely follow expected residual load patterns, thereby ensuring consistency with historically observed reservoir management behaviour.

text: 84 Relevance: Hydropower plays a central role in adequacy assessments because of its ability to shift energy across hours, days, and seasons. The modelling approach used affects the operational flexibility of hydropower units, their ability to provide energy during scarcity, and the consistency of dispatch with historical practice and environmental constraints. Differences in hydropower modelling can affect LOLE outcome, particularly in systems with significant reservoirs and pumped-storage capacity such as France.

text: 85 Assessment: By introducing a residual-load-based pre-allocation heuristic, the French NRAA ensures that hydropower generation patterns remain consistent with historical reservoir management practices. This provides a conservative yet credible estimation of hydropower’s contribution to adequacy. ACER therefore considers the difference justified. Difference #13 Alternative revenues (see Section 2.2.6. in the NRAA)

text: 86 Description: The French NRAA EVA explicitly accounts for additional revenues from ancillary services such as balancing capacities provision. These revenues are included when estimating A C E R O P I N I O N N O 1 2 / 2 0 2 5 capacities’ NPV, thereby influencing investment and retirement decisions. The calibration of ancillary revenues is performed through two complementary approaches carried out ex-ante.

text: 87 First, a historical method relies on historical remuneration patterns observed for different technologies, notably CCGTs, OCGTs, and demand response. Second, a forward-looking, prospective approach models both future ancillary services prices and the volumes of capacities expected to be engaged by 2030. In this prospective model, both demand and supply of ancillary services are explicitly modelled, allowing the optimisation of the participation of FCR/aFRR certified capacities in face of the ancillary services requirements, accounting for their associated costs.

text: 88 By contrast, ERAA does not include ancillary services revenues in its EVA. To ensure that the operational availability of assets reflects their obligations to provide frequency containment and restoration reserves, two modelling approaches are available in ERAA. It either reserves a share of thermal, renewables, or hydro capacity for the provision of system services, or specifies the reserve requirement which could be covered by thermal units. The choice between these two approaches depends on the way individual TSOs provide national data for the ERAA assessment.

text: 89 Relevance: Ancillary services revenues can materially impact the economic viability of certain technologies, especially flexible assets with fast activation capability such as OCGTs, batteries, and hydropower units. The inclusion of those revenues increases the expected income of those capacities, reducing their likelihood of decommissioning, and thereby mitigating adequacy concerns.

text: 90 Assessment: The inclusion of expected revenues from other electricity-related services is explicitly required by

text: Article 6(9)

text: (b) of the ERAA methodology. ACER considers that in this respect, the RTE approach constitutes good practice as it provides a more complete representation of actual market incentives faced by investors in France. The difference with ERAA 2024 is therefore considered justified.

text: 3.4. Additional analysis on difference 8. and 10.

text: 91 As outlined in Section 3.3, some of the differences linked to the modelling of revenues are considered not justified, namely the static price cap, the lack of consideration of forward markets, and the discarding of the revenues from the highest-revenue MC scenarios rather than their discounting. For the unjustified differences, the French NRAA provided sensitivity analyses measuring their impact on adequacy outcomes. These sensitivities highlight that, when considered in isolation, LOLE levels are reduced but remain higher than the French reliability standard. It is, however, necessary to assess whether this would still hold if all unjustified differences were corrected simultaneously.

text: 92 In this context, during the opinion process, ACER, the French Ministry and RTE agreed that RTE would run an additional scenario to demonstrate whether the adequacy concern would still materialize. The parameters of this additional scenario run by RTE are as follows: • Lower the risk aversion parameter from 10% to 5% in order to reflect the hedging possibilities through forward markets; • Price caps aligned with the increasing limits derived in ERAA 2024; • Discounting rather than discarding exceptional revenues A C E R O P I N I O N N O 1 2 / 2 0 2 5

text: 93 Table 7 summarizes the results of the sensitivity analyses done for difference 8. and 10. in isolation and the combined sensitivity with the total impact. Revenues CVaR LOLE EENS Price caps above CVaR parameter (h) (GWh) parameter 4000 Reference case 10% Discarded 19.8 73.8 EUR/MWh CVaR 5% sensitivity 4000 5% Discarded 12.5 41.1 EUR/MWh (see Difference 8) Price cap sensitivity ERAA 2024 10% Discarded 16.9 60.5 (see Difference 10) Combined scenario ERAA 2024 5% Discounted 6.5 16.7

text: 94 The results of this scenario confirm the significant impact of parameters related to revenues on adequacy outcomes, with LOLE levels decreasing from 19.8 hours in the reference case to 6.5 hours. Nevertheless, LOLE remains above the French reliability standard of 2 hours. Accordingly, this additional scenario, while more favorable to investment in capacity, does not alter the conclusion of the French NRAA that indicates insufficient capacity levels in the 2030/2031 target year. ACER considers that this combined scenario would be an appropriate Central Reference Scenario to identify adequacy concerns.

text: 95 ACER further notes that this additional combined scenario does not account for the increased NTC capacities included in the cross-border exchanges sensitivity (See Difference 11). While the impact of these additional NTC capacities between France and the CORE region is expected to be limited (given that the LOLE decreased by only 0.2h in the sensitivity), ACER considers their inclusion represents best practice to assess the combined impact of all unjustified differences on adequacy outcomes. A C E R O P I N I O N N O 1 2 / 2 0 2 5

text: 4. Conclusions

text: 96 ACER has assessed the differences between the French NRAA and ERAA 2024 as listed in Table 8. The combination of these differences leads to a divergence in the adequacy results between the two assessments.

text: 97 ACER considers most of the differences between the French NRAA and the ERAA 2024 edition to be justified. However, ACER finds three differences, #8, #10 and #11, not justified. The previous section explains ACER’s position and offers recommendations for improvements.

text: 98 Nonetheless, as confirmed by the sensitivities provided by the French TSO, the overall impact of these differences on adequacy results (LOLE) does not alter the conclusion of the French NRAA. ACER suggests that the French authorities consider the recommendations made in this Opinion to ensure that the magnitude of the adequacy concern is more accurately captured.

text: 99 Considering the above, ACER is of the view that overall, the French NRAA identifies adequacy concern in a robust manner. ACER also recognises that the revenues-based modelling approach, the assumption that other Member States will, at a minimum, meet their respective reliability standards, and the consideration of alternative revenues are good practices. A C E R O P I N I O N N O 1 2 / 2 0 2 5 This Opinion is addressed to the French Ministry of Energy and Climate - Direction Generale de l’Energie et du Climat (DGEC). Done at Ljubljana, on 15 December 2025. — SIGNED — V. ZULEGER, ACER Director ad interim


text: EirGrid is legally required, under the Electricity Regulation Act (S.I. No. 60 of 2005 and S.I. No. 445 of 2000), to publish forecast information relating to the operation of the power system. SONI’s TSO licence places a formal obligation on it to prepare and publish an annual Generation Capacity Statement, outlining expected future supply and demand conditions.

text: Table 1 LOLE per region and the Reliability Standard (hours): AIRAA 2026-2035 vs. ERAA 2025

text: Region LOLE 2028 2030 2033 2035

text: Ireland Reliability Standard 3.00 3.00 3.00 3.00 Ireland ERAA 2025 1.62 2.05 2.99 3.52 Ireland AIRAA 2026-2035 7.95 0.37 0.74 1.57 Northern Ireland Reliability Standard 4.90 4.90 4.90 4.90 Northern Ireland ERAA 2025 0.61 1.06 1.15 2.95 Northern Ireland AIRAA 2026-2035 2.89 3.35 7.30 11.26 SEM Reliability Standard 6.50 6.50 6.50 6.50 SEM ERAA 2025 2.04 2.66 3.48 4.43 SEM AIRAA 2026-2035 - - 0.10 0.44 Source: ACER based on ERAA 2025 and AIRAA 2026-2035 data

text: Table 2 Differences in AIRAA 2026-2035, compared with ERAA 2025: Rationale and impact on LOLE

text: Impact on # Where? What? Reason IE NI SEM LOLE

text: Method Regional scope Simplification inconclusive ✓ ✓ ✓ 2 Method No flow-based market coupling Simplification inconclusive ✓ ✓ ✓ 3 Method No curtailment sharing Simplification decrease ✓ ✓ ✓ 4 Method No economic viability assessment Simplification decrease ✓ ✓ ✓ 5 Method More forced outage samples National specificity inconclusive ✓ ✓ ✓ 6 Method More planned maintenance samples National specificity inconclusive ✓ ✓ ✓ 7 Method Restricted operating hours National specificity increase ✓ ✓ ✓ 8 Method More constrained battery model National specificity increase ✓ ✓ ✓ 9 Method Limited grid feed-in in Dublin National specificity increase ✓ ✓ ✓ nd 10 Method No 2 North-South Interconnector National specificity increase ✓ ✓ ✗ 11 Input data Reduced electricity demand Data update decrease ✓ ✓ ✓ 12 Input data Higher non-renewable generation capacity Data update decrease ✓ ✓ ✓ 13 Input data Reduced renewable generation Data update increase ✓ ✓ ✓ 14 Input data Delayed Celtic Interconnector Data update increase ✓ ✓ ✓ Source: ACER based on AIRAA 2026-2035

text: As per ERAA methodology, ‘Non-explicitly modelled zones are represented by fixed time series of energy exchanges through interconnections’.

text: Technical Annex to the ACER Decision No 06/2026

text: AIRAA 2026-2035 already incorporated revenues from ancillary services in most EVA sensitivity runs.

text: In the ERAA 2025 modelling results, averaged across target years for the SEM, while most ENS hours occur within the defined operating window of 16:00-22:00, 45% falls outside this period, and 11% of ENS events have a duration exceeding six hours.

text: See https://www.soni.ltd.uk/community/projects-in-your-area/north-south-interconnector.

text: The trends and projections scenario is included in the amended ERAA methodology, which provides information on its definition and modelling approach. 8 See National Energy Demand Strategy.

text: Table 3 Differences in AIRAA 2026-2035, compared with ERAA 2025: Rationale and assessment

text: # Where? What? Reason Justified

text: Method Regional scope Simplification justified 2 Method No flow-based market coupling Simplification justified 3 Method No curtailment sharing Simplification justified 4 Method No economic viability assessment Simplification not justified 5 Method More forced outage samples National specificity justified 6 Method More planned maintenance samples National specificity justified 7 Method Restricted operating hours National specificity not justified 8 Method More constrained battery model National specificity justified 9 Method Limited grid feed-in in Dublin National specificity justified nd 10 Method No 2 North-South Interconnector National specificity not justified 11 Input data Reduced electricity demand Data update justified 12 Input data Higher non-renewable generation capacity Data update justified 13 Input data Reduced renewable generation Data update justified 14 Input data Delayed Celtic Interconnector Data update justified

identifier: ACER Opinion No 12/2026

publisher: Europeiska unionens byrå för samarbete mellan energitillsynsmyndigheter

sprak: en

title: ACER Opinion 12-2026 on All-Island Resource Adequacy Assessment: Ireland and Northern Ireland

serie: yttranden

text: No 12/2026

type: rubrik

text: OPINION

text: on All-Island Resource Adequacy Assessment: Ireland and Northern Ireland

text: 7 May 2026

text: A C E R O P I N I O N N O 1 2 / 2 0 2 6

type: stycke

text: Executive summary

text: Under the Electricity

text: Regulation (EU) 2019/943

text: , the European Network of Transmission System Operators for Electricity (ENTSO-E) conducts annual European resource adequacy assessments (ERAAs). Member States may perform national resource adequacy assessments (NRAAs) to capture local developments. If an NRAA identifies risks not reflected in the ERAA, it must be submitted for ACER’s opinion, along with an explanation of the differences between the national and European assessments. EirGrid and SONI – the Transmission System Operators (TSOs) for Ireland and Northern Ireland, respectively – conducted the All-Island Resource Adequacy Assessment 2026-2035 (AIRAA 2026- 2035), published on TSO’s websites (EirGrid, SONI). The AIRAA 2026-2035 complements ERAA 2025 by reflecting recent developments specific to the Single Electricity Market (SEM), which comprises Ireland and Northern Ireland. AIRAA 2026-2035 delivers three distinct assessments – covering Ireland, Northern Ireland, and the SEM as a whole – all of which are reviewed by ACER.

text: Key Findings of AIRAA 2026-2035 base (central reference) scenario

text: • Ireland: Adequacy risk in 2028, with LOLE of 7.95 hours – higher than in ERAA 2025 (1.62 hours) and above the 3-hour reliability standard; primarily driven by delays to new capacity entering the market and the delayed Celtic Interconnector. • Northern Ireland: Risks in 2033 and 2035, with LOLE of 7.30 and 11.26 hours, respectively – above ERAA 2025 estimates (1.15 and 2.95 hours) and exceeding the 4.9-hour standard; mainly driven by the absence of the planned second North-South Interconnector (to be commissioned in 2031) and lower projected wind generation.

text: ACER found the following differences justified

text: • Simplifications in AIRAA 2026-2035: regional scope, exclusion of flow-based market coupling, and omission of curtailment sharing - have minimal impact due to the SEM’s limited interconnection with its neighbours, while reducing modelling complexity. • Methodological improvements: more outage sample runs, detailed battery modelling, and grid feed-in constraints in Dublin – improve accuracy. • Input data update: demand, resources, delayed Celtic Interconnector - reflect recent trends.

text: ACER found the following differences not justified

text: • Assumptions restricting gas-fired peaking units to a fixed evening operating window ignore seasonal scarcity, and including the planned second North-South Interconnector in the SEM assessment only. • The Economic Viability Assessment (EVA), although developed, was not included in the base (central reference) scenario. It should be, as it is a legally required element of the analysis and is necessary to assess whether capacity is financially viable in the market and therefore likely to be built or maintained.

text: Conclusion and Recommendations

text: ACER finds most differences justified, but highlights gaps: (i) missing EVA modelling phase in the base scenario, (ii) including the second North-South Interconnector in the SEM assessment only, and (iii) restrictive operation assumptions on peaking units. To address these gaps, ACER recommends: • Including EVA in the base (central reference) scenario, ensuring it incorporates revenue stacking, and demand-side unit expansion, and maintaining revenue consistency between EVA and economic dispatch models. • Modelling increased operational flexibility for the constrained peaking units during scarcity. • Reflecting planned key infrastructure developments in all assessments.

text: A C E R O P I N I O N N O 1 2 / 2 0 2 6

text: 1. Background

text: Article 20 of Regulation (EU) 2019/943

text: (Electricity Regulation) requires Member States to monitor resource adequacy within their territory based on the European Resource Adequacy Assessment (ERAA). It also allows them to complement ERAA by conducting a National Resource Adequacy Assessment (NRAA) according to Article 24 of the Electricity Regulation. Either of the two assessments can identify resource adequacy concerns, but both assessments must be based on the ERAA methodology. The adequacy concerns identified through these assessments should be in the first place addressed by eliminating regulatory distortions or market failures, and, where it does not suffice, by introducing capacity mechanisms.

text: 2 According to Article 24(3) of the Electricity Regulation, where the NRAA identifies an adequacy concern that was not identified in ERAA, the NRAA must include reasons for the divergence between the two assessments, including details of the sensitivities used and the underlying assumptions. The Member State must publish the NRAA and submit it to ACER for opinion. ACER’s opinion assesses, on a case-by-case basis, whether the differences between the two assessments are justified. ACER primarily considers the differences identified and reasoned by the Member State in the submission, but may also identify further differences, if they also have a material impact on the results.

text: 3 The national body that is responsible for the NRAA, which can be a transmission system operator (TSO) or a different body designated by the Member State, must take due account ACER's opinion, and, where necessary, amend its assessment. Where it decides not to take ACER's opinion fully into account, it must publish a report with detailed reasons.

text: 4 The latest ERAA (ERAA 2025) was published in December 2025. To complement it, EirGrid and SONI, the TSOs for Ireland and Northern Ireland respectively, jointly carried out the All-Island Resource Adequacy Assessment 2026-2035 (AIRAA 2026-2035), published on TSO’s websites (EirGrid, SONI). The assessment constitutes an NRAA within the meaning of Article 24 of the Electricity Regulation. AIRAA 2026-2035 was published on 26 February 2026. On 10 March 2026, Ireland’s Department of Climate, Energy and the Environment submitted the AIRAA to ACER, together with the reasons for its divergence from ERAA 2025, as well as details of the sensitivities used and the underlying assumptions. On 30 March, ACER received the corresponding submission from the Department for the Economy of Northern Ireland.

text: 5 This Opinion evaluates whether the differences between AIRAA 2026-2035 and ERAA 2025 are justified. It is addressed to Ireland’s Department of Climate, Energy and the Environment, and to the Department for the Economy of Northern Ireland, and is issued in accordance with

text: Article 9(2) of Regulation (EU) 2019/942

text: and Article 24(3) of the Electricity Regulation.

text: 2. Summary of AIRAA 2026-2035

text: 6 The aim of AIRAA 2026-2035 is to complement the ERAA 2025 by capturing recent market trends in resource deployment and demand within the Single Electricity Market (SEM), comprising Ireland and Northern Ireland. It also applies modelling approaches that more accurately reflect the technical performance of the SEM electricity system, based on local specificities and historical observations.

text: 7 AIRAA 2026-2035 provides adequacy results for three regions: (1) Ireland, (2) Northern Ireland, and (3) the SEM – All-Island. The modelling adequacy results of the base (central reference) A C E R O P I N I O N N O 1 2 / 2 0 2 6 scenario are shown in Table 1. AIRAA 2026-2035 identifies new adequacy concerns that were not detected in ERAA in both bidding zones – specifically, in Ireland in 2028 and in Northern Ireland in 2033 and 2035 – as the modelled Loss of Load Expectation (LOLE) exceeds the respective reliability standards, which are 3 hours for Ireland and 4.9 hours for Northern Ireland.

text: 8 This divergence in the LOLE results is due to differences in the modelling assumptions in the base scenario between AIRAA 2026-2035 and ERAA 2025. These differences are discussed and assessed by ACER in the following section.

text: 3. ACER’s assessment

text: 9 ACER welcomes AIRAA 2026-2035 and considers it a well-developed assessment of the SEM electricity system, enriched with local details and capturing recent system developments. The assessment report provides a clear description of the methodological modelling assumptions.

text: 10 ACER also appreciates EirGrid and SONI for providing a comprehensive comparison between AIRAA 2026-2035 and ERAA 2025, including a clear description and explanation of the differences and their potential impact on adequacy results.

text: 11 The differences between the AIRAA 2026-2035 base scenario and the ERAA 2025 central reference scenario fall into two categories: (i) methodological and (ii) input data. Each difference is listed in Table 2, along with its rationale, potential impact on LOLE and the assessment in which it is applied. A detailed description of these differences is provided later in this section. A C E R O P I N I O N N O 1 2 / 2 0 2 6

text: 12 ACER notes that the 2 North-South interconnector is considered only in the SEM assessment, distinguishing it from the two other assessments. The project is expected to become operational by the end of 2031. The SEM adequacy results presented in Table 1 demonstrate its importance: inclusion of the interconnector ensures that LOLE in the SEM remains below the reliability standard in the modelled target years 2033 and 2035, thereby strengthening the security of electricity supply across the island. This contrast also highlights that increased cross-zonal capacity supports resource adequacy.

text: 3.1. Method

text: Difference #1 Regional scope

text: 13 Description: AIRAA 2026-2035, compared to the pan-European ERAA, has a smaller geographic scope, focusing on the Single Electricity Market (SEM), comprising Ireland and Northern Ireland, and its neighbouring bidding zones of Great Britain and France. The neighbouring electricity systems are calibrated to their respective reliability standards, ensuring sufficient standardcompliant resource capacity. This calibration is performed through the iterative addition of perfect generation (or demand) until each region meets the target LOLE (3 hours) defined by its reliability standard.

text: 14 Power imports from non-modelled countries are represented as fixed exchanges derived from the results of ERAA 2024. These exchanges are specific to both the target year and the weather scenario.

text: 15 Relevance: Reducing the geographical scope in electricity system modelling reduces complexity and modelling time. This enables faster and more resource-efficient analyses while allowing for a deeper focus on a specific region.

text: 16 Assessment: The reduced spatial coverage in AIRAA 2026-2035 includes the key relevant regions: the SEM and its direct neighbours, Great Britain and France. As the neighbouring countries are significantly larger than the SEM, their inclusion provides an adequate representation of the external systems most relevant for cross-border exchanges. By calibrating neighbouring regions to their reliability standard, the model ensures the SEM neither relies excessively on imports nor is constrained by energy-dependent neighbouring regions. When combined with fixed, target-year- and weather-scenario-specific exchanges with non-modelled bidding zones, this approach ensures consistency with the ERAA framework and is therefore considered justified. Difference #2 No flow-based market coupling

text: 17 Description: Flow-based market coupling (FBMC), while present in ERAA, is absent in AIRAA 2026-2035. Instead, net transfer capacity (NTC) limits are applied among the modelled bidding zones.

text: 18 Relevance: FBMC models cross-border electricity trade by reflecting the physical constraints of the interconnected transmission networks within bidding zones rather than treating interconnectors as independent links. In European markets these constraints are incorporated in the EUPHEMIA, which determines day-ahead prices and exchanges. In ERAA, modelling FBMC helps capture how neighbouring systems can support each other during scarcity events, influencing estimates of LOLE and the contribution of interconnections to system adequacy.

text: 19 Assessment: AIRAA 2026-2035 focuses on the SEM, rather than the meshed AC network of continental Europe where FBMC provides the greatest benefits. The SEM is not part of the Core A C E R O P I N I O N N O 1 2 / 2 0 2 6 Capacity Calculation Region in which FBMAC is applied. In addition, the geographic scope of AIRAA 2026-2035 does not extend to the full Core region, and its modelling approach already captures support from Great Britain and France through calibration to their respective reliability standards. Thus, excluding FBMC in AIRAA 2026-2035 is considered justified. Difference #3 No curtailment sharing

text: 20 Description: The optional curtailment sharing feature, while present in ERAA, is not included in AIRAA 2026-2035. The curtailment sharing ensures that energy shortages are fairly distributed across bidding zones whose domestic capacity is not sufficient to meet local demand. This reflects the actual functioning of the spot markets.

text: 21 Relevance: Curtailment sharing is embedded in the EUPHEMIA algorithm for day-ahead electricity trade among EU bidding zones. It spreads more evenly the impact of network constraints on scarcity experienced in the interconnected bidding zones. When applied to future electricity system modelling, this feature is relevant in multi-bidding-zone simulations to ensure accurate LOLE results in markets facing resource scarcity.

text: 22 Assessment: Curtailment sharing can have a significant impact on LOLE results. In ERAA, its application roughly doubled the average LOLE per bidding zone, as explained in ACER’s ERAA 2025 Decision. However, the impact of curtailment sharing in the SEM is limited due to the island’s geographic position, being connected only to the bidding zones of Great Britain and France. According to ERAA 2025 , the SEM experiences a minor change in adequacy outcomes when curtailment sharing is applied: the feature increases LOLE by 1 to 2 hours in Ireland and up to 1 hour in Northern Ireland depending on target year. This confirms the low impact of the curtailment sharing in the SEM. Thus, its omission in AIRAA 2026-2035 is considered justified. Difference #4 No economic viability assessment

text: 23 Description: The Economic Viability Assessment (EVA), while included in AIRAA 2026-2035, is absent from the base (central reference) scenario. As the result, the Economic Dispatch (ED) adequacy model operates using the initial resource capacity assumptions without evaluating the economic feasibility of either existing assets or new resource candidates.

text: 24 Relevance: EVA assesses whether existing and prospective power resources are financially sustainable within an energy-only market. It serves as a proxy for investor behaviour, to identify which assets are likely to remain operational, be decommissioned, or be newly developed. In doing so, it provides a more realistic basis for evaluating future supply adequacy.

text: 25 Assessment: EVA is a useful component of ERAA, as it goes beyond simply checking whether enough electricity capacity exists – it evaluates whether that capacity is financially sustainable and likely to be built, maintained, or retired. Without EVA, ERAA risks misestimating security of supply and potentially leading to suboptimal policy decisions. Therefore, its omission from AIRAA 2026-2035 is not justified.

text: 26 Although EVA is not included in the base scenario of AIRAA 2026-2035, it is incorporated in several sensitivity scenarios. These scenarios assess resource entry and exit based on profitability, indicating the retirement of gas turbines in the SEM across all target years and in all sensitivity scenarios. In the low battery cost sensitivity, battery storage is deployed.

text: 27 ACER recommends including the EVA modelling phase in the base scenario of the assessment.

text: 28 ACER recommends that the assessment ensures strong consistency between EVA and ED models, so that investment decisions (i.e. capacity adjustments) derived from EVA align with the security of supply outcomes assessed in ED. Particular attention should be paid to the selection of weather scenarios in EVA. These scenarios should capture the overall climatic variability in A C E R O P I N I O N N O 1 2 / 2 0 2 6 the SEM present across the complete ED scenario set. This will help ensure that the EVA model identifies the consistent level of investment. In addition, revenues observed under the selected EVA scenarios should be representative of revenues across the entire ED scenario set, ensuring alignment between the two models. Also, technical constraints should well align in two models.

text: 29 ACER recommends that the assessment considers incorporating modelling revenue stacking within the EVA, with particular relevance for battery storage while remaining applicable to all generation and demand-side resources. Revenue streams may include, for example, energy market trade (arbitrage) – including intraday and balancing markets – as well as provision of ancillary/system services under the Delivering a Secure, Sustainable Electricity System (DS3) programme, as highlighted in the Electricity Storage Policy Framework for Ireland.

text: 30 ACER recommends that the assessment considers demand side units (DSU) as potential expansion candidates within EVA. Relevant economic parameters and expansion potentials can be sourced from publicly available data, including datasets consulted on in March 2026 and to be published by ACER. EirGrid and SONI White Paper highlights demand-side flexibility as a key resource for achieving renewable energy and emissions targets while enhancing security of supply, signalling a clear policy direction to expand and incentivise DSU deployment across both Ireland and Northern Ireland. Difference #5 More forced outage samples

text: 31 Description: In ERAA 2025, each weather scenario within each target year is simulated with 15 different forced outage runs. In AIRAA 2026-2035 this is increased to 30 forced outage runs per scenario, which is considered sufficient under the ERAA methodology, as it provides a formal convergence criterion to verify that additional samples no longer yield a meaningful improvement in modelling accuracy.

text: 32 Relevance: Multiple forced outage runs provide robust LOLE results accounting for uncertainty, capturing a wide range of potential outcomes and providing a more realistic analysis. This approach is especially important for smaller power systems, where a higher ratio of single‑plant capacity to peak demand makes the system far more sensitive to random unit outages.

text: 33 Assessment: Unlike Europe-wide system in ERAA, where 15 forced outage runs are sufficient, the smaller SEM is more sensitive to conventional generator outages, requiring additional modelling runs to ensure convergence and robust adequacy assessment, providing a more accurate representation of system reliability under various outage scenarios. Therefore, the 30 forced outage runs in AIRAA 2026-2035 are both appropriate and justified. Difference #6 More planned maintenance samples

text: 34 Description: ERAA 2025 applies a single maintenance profile per target year reflecting the average level of planned outages. In AIRAA 2026-2035, each simulation run – defined by the combination of target year, weather scenario, and forced outage sample – uses a slightly different reoptimized planned maintenance profile. Consequently, a new optimised maintenance schedule is generated for every run. Maintenance events are predominantly scheduled during low-demand seasons, but they may also occur during scarcity periods at times of peak demand.

text: 35 Relevance: Capturing the historical seasonal pattern of planned maintenance – especially the unavoidable maintenance near scarcity periods – is crucial for accurate future electricity system modelling. This feature ensures realistic reliability assessment, as such maintenance can directly limit resource availability during scarcity.

text: 36 Assessment: Historical data from the SEM indicates that planned maintenance does not always occur strictly within the optimal window. Modelling the historical frequency and randomness of A C E R O P I N I O N N O 1 2 / 2 0 2 6 these events during scarcity – using 30 samples per target year and per weather scenario – therefore brings the simulation results closer to real system behaviour. This approach is justified and aligns with the ERAA methodology, which requires planned outage schedules to be optimised to avoid maintenance during likely ENS periods, while still respecting the share of capacity that must undergo maintenance in winter. Difference #7 Restricted operating hours

text: 37 Description: Operating hours for peaking gas-fired generation units in Northern Ireland are capped under the Pollution Prevention and Control regulatory framework: units summing to 270 MW are limited to 500 hours per year, while units summing to 510 MW may operate up to 1500 hours annually.

text: 38 In ERAA, dispatch of these constrained units is optimized assuming perfect foresight across the full modelling horizon. In contrast, AIRAA 2026-2035 imposes operational restrictions: units subject to the 1500-hour limit may run for up to six hours per day within a fixed evening peak window (16:00–22:00), while those under the 500-hour limit are restricted to a maximum of four hours per day within a narrower window (17:00–21:00).

text: 39 Relevance: Restrictions on the operating hours of power plants can affect the availability of resource capacity during periods of system stress. Units subject to limited operating hours provide less reliability value than fully available plants. Incorporating these constraints properly ensures that reliability assessments capture the operational challenges associated with emissions-driven restrictions.

text: 40 Assessment: The concern is not the existence of an annual emissions-related running-hour limit as such, but the rigid daily allocation of those hours in the adequacy modelling. The fixed daily operating window for the constrained units may restrict their contribution during times of system scarcity. Scarcity events are often seasonal and can extend outside the restricted operational window. Applying a uniform daily constraint throughout the year fails to account for this seasonality, while a rigid schedule limits the units’ ability to respond to longer-duration or off-peak scarcity events . For these reasons, the constraint is not justified.

text: 41 ACER recommends that the assessment provides greater flexibility for thermal units with limited annual operating hours. This could include allowing operators to allocate a larger share of their operating hours to periods when resource scarcity is expected, thereby aligning the use of constrained units more closely with the seasonal pattern of scarcity events. In addition, operational frameworks should permit these units to run for longer continuous durations – exceeding daily hour limit where necessary – since scarcity events may occur outside the predefined window and last longer , while thermal units are capable of sustained operation provided that fuel supply is maintained. Difference #8 More constrained battery model

text: 42 Description: Compared with ERAA 2025, which models a single aggregated battery per bidding zone, AIRAA 2026-2035 models individual battery units with unit-specific capacity and duration. It further categorises batteries into three sub-groups based on duration: less than one hour, 1 to 4 hours, and more than 4 hours. Battery duration indicates how long a fully charged battery can operate at full power.

text: 43 In addition, AIRAA 2026-2035 introduces two refinements, not present in ERAA 2025. First, it incorporates forced outage rates for batteries. Second, based on an analysis of connection A C E R O P I N I O N N O 1 2 / 2 0 2 6 contract data, it limits battery charging power to 50% of the installed capacity. This limitation applies only to batteries already in the system and not to new batteries in the generation forecast.

text: 44 Relevance: Accurately representing battery size, availability and operational constraints is crucial for modelling power scarcity events. These constraints are key parameters in adequacy assessments, as they directly determine resource ability to cover scarcity periods and, consequently, affect the reliability of the results.

text: 45 Assessment: Incorporating detailed characteristics of both existing and planned batteries in the SEM – reflecting both actual duration and availability – enhances modelling accuracy and is therefore justified. Difference #9 Limited grid feed-in in Dublin

text: 46 Description: Maximum electricity generation from conventional power plants in the Dublin area is constrained, as not all available generation can be dispatched simultaneously without overloading power grid.

text: 47 Relevance: These generation limits restrict the effective utilisation of available resource capacity, particularly during periods of system stress. As a result, power plants subject to such constraints contribute less to overall system reliability compared to an unconstrained generation fleet, since their dispatch may be capped below their technical availability.

text: 48 Assessment: High short-circuit levels – often exceeding equipment design limits – can arise during peak winter evening demand or when renewable output is low and more conventional generation is online. This issue is particularly pronounced in the Dublin region due to rapid demand growth. AIRAA 2026-2035 accounts for these operational constraints, limiting the simultaneous operation of conventional generators in Dublin. In doing so, it captures the specific characteristics of the local transmission system, thereby justifying the adopted approach. Difference #10 No 2 North-South Interconnector

text: 49 Description: The second North–South Interconnector (linking Northern Ireland and Ireland) is assumed to be operational from 2031 in ERAA 2025. However, it is not included in the national adequacy assessments for either Ireland or Northern Ireland. The project has been under development for over 15 years and is now fully consented and entering a critical stage of delivery. Excluding the second North-South interconnector at this juncture from the jurisdictional assessments illustrates potential adequacy concerns should the two jurisdictions continue to share constrained interconnection while the project is under delivery. Notably, this differs from the overall SEM (All-Island) assessment, which does consider the interconnector from 2031.

text: 50 Relevance: Accurately reflecting the deployment of planned transmission infrastructure is essential for producing credible resource adequacy projections, as it represents the most likely evolution of the power system.

text: 51 Assessment: Acknowledging the interconnector is included in the All-Island assessment, the exclusion of the interconnector from jurisdictional assessments is not justified. As its purpose is to relieve a bottleneck on the grid between the Irish and Northern Ireland jurisdictions , omitting this planned development prevents the model from realistically representing future system conditions and is likely to result in an overestimation of adequacy risks.

text: 52 ACER recommends that the assessment includes the second North-South Interconnector in the jurisdictional assessments. A C E R O P I N I O N N O 1 2 / 2 0 2 6

text: 3.2. Input data

text: Difference #11 Reduced electricity demand

text: 53 Description: Compared to ERAA 2025, in AIRAA 2026-2035 both annual demand volumes and peak demand in the two bidding zones – Ireland and Northern Ireland – are slightly lower reflecting recent demand developments and national targets. Depending on the target year, annual demand decreases by between nearly 0% and 3% in Ireland, and between 4% and 7% in Northern Ireland. Peak demand, meanwhile, declines by 1% to 2% in Ireland and by 2% to 6% in Northern Ireland.

text: 54 Relevance: Accurately capturing the most recent historical developments in electricity demand is essential for producing credible resource adequacy projections. It ensures that the initial years of the forecast reflect actual system behaviour.

text: 55 Assessment: AIRAA 2026-2035 incorporates updated demand profiles that reflect the latest observed trends in the SEM, including economic growth, the deployment of heat pumps and electric vehicles, overall load growth (including the expansion of data centres), and changes in demand flexibility affecting both baseload and peak demand. Incorporating these developments is well justified, as it enables the model to better capture both the magnitude and temporal profile of future demand, leading to more robust adequacy conclusions.

text: 56 This approach is also in line with the trends and projections scenario defined in the amended ERAA methodology. This scenario aims to capture the actual pace of the energy transition, which develops further from current levels but could remain below the trajectories envisioned in the NECPs .

text: 57 In light of the rapid deployment of data centres in Ireland the Irish energy regulator has introduced a grid connection policy for data centres. The primary aim of this policy is to ensure security of supply while promoting renewable energy targets. Under this policy, data centres must provide onsite (or proximate) generation capacity equivalent to their peak grid demand.

text: 58 ACER recommends that the assessment – including inputs to forthcoming ERAAs – continue to account for demand flexibility in the context of rapid demand growth. This should include modelling the expansion of explicit demand-side resources across the entire time horizon. Such approach should capture emerging sources of flexible demand, such as data centres with demand response capabilities (e.g. onsite dispatchable generation that can also participate in electricity markets), as well as the effects of national policies and incentives aimed at activating additional flexibility .

text: 59 In AIRAA 2026-2035, however, the expansion of explicit demand-side resources is only considered up to 2029, with capacity assumed to remain constant through 2035. Although demand forecast does include flexibility from electric vehicles and smart meters, contributing to peak demand reduction, the lack of continued growth in explicitly modelled demand-side resources may underrepresent full future flexibility potential and could lead to an overestimation of system risks. A C E R O P I N I O N N O 1 2 / 2 0 2 6 Difference #12 Higher non-renewable generation capacity

text: 60 Description: Compared to ERAA 2025, AIRAA 2026-2035 incorporates recent resource capacity updates. Higher conventional generation capacity in Ireland – by 61 MW in 2028 and by 461 MW over the period 2030-2035. Battery storage capacity is also higher in AIRAA 2026-2035 – by 2 MW in 2028 and by 432 MW between 2030 and 2035 in Ireland. In Northern Ireland, battery storage capacity is higher by 20 MW in 2028 and by 40 MW over the period 2030-2035.

text: 61 Relevance: Accurately capturing the most recent historical developments in resource capacity is essential for producing credible resource adequacy projections. It ensures that the initial years of the forecast reflect actual system behaviour.

text: 62 Assessment: AIRAA 2026-2035 incorporates updated resource capacities that reflect outcomes from the most recent capacity auctions, as well as revised expectations for the commissioning of new resources within the SEM. Incorporating these developments is well justified, as it enables the model to better capture capacity of future resources, leading to more robust adequacy conclusions.

text: 63 Note, resource viability assessment in AIRAA 2026-2035 (applied only in sensitivity scenarios) indicates potential decommissioning of gas-fired power plants in the SEM from 1000 to 2500 MW, depending on the target year and sensitivity assumptions.

text: 64 ACER recommends that the assessment – including inputs to forthcoming ERAAs – ensure that initial assumptions on battery storage (prior to EVA investment modelling) account for expected developments in the electricity system that may enable greater deployment of storage outside of capacity mechanisms in the coming years. In AIRAA 2026-2035, battery deployment in the SEM does not extend beyond 2030; installed capacity in 2030 is assumed to remain unchanged through to 2035. Difference #13 Reduced renewable generation

text: 65 Description: Compared to ERAA 2025, AIRAA 2026-2035 projects lower renewable capacity in Northern Ireland, with reduction of 90 MW in 2028, 566 MW in 2030, 765 MW in 2033 and 380 MW in 2035. These adjustments are based on updated information regarding the pipeline of planned renewable energy projects.

text: 66 In addition, AIRAA 2026-2035 applies downward scaling to onshore and offshore wind generation profiles used in ERAA 2025, based on historically observed availability in the last 12 years. In Ireland, onshore wind capacity factors are reduced from an average of 45% to 30% across all weather scenarios, while offshore wind capacity factors are reduced from 54% to 46%. In Northern Ireland, onshore wind capacity factors are adjusted from 42% to 29%, and offshore wind capacity factors from 47% to 45%.

text: 67 Relevance: Accurately capturing the most recent historical developments in resource capacity deployment is essential for producing credible resource adequacy projections. It ensures that the initial years of the forecast reflect actual system behaviour.

text: 68 Assessment: The primary recent driver of renewable capacity deployment in Northern Ireland is the development of a new government-backed support mechanism, the Renewable Electricity Price Guarantee (REPG). This scheme, together with the broader Path to Net Zero strategy and its 2030 target of achieving at least 80% renewable electricity, establishes the auction framework for future renewable capacity deployment.

text: 69 AIRAA 2026-2035 incorporates updated renewable capacity projections for Northern Ireland, reflecting the current project pipeline. Combined with the adjustment of wind generation profiles in the SEM based on historical observations, the renewable generation assumptions in the AIRAA 2026-2035 are both appropriate and well justified. A C E R O P I N I O N N O 1 2 / 2 0 2 6 Difference #14 Delayed Celtic Interconnector

text: 70 Description: While the Celtic Interconnector (Ireland-France) is assumed to be available from the start of 2027 in ERAA 2025, AIRAA 2026-2035 reflects a delay, with availability now expected from April 2028.

text: 71 Relevance: Accurately capturing the most recent updates on infrastructure development is essential for producing credible resource adequacy projections. It ensures that the initial years of the forecast reflect actual system behaviour.

text: 72 Assessment: AIRAA 2026-2035 incorporates construction delays affecting the Celtic Interconnector, shifting its availability to April 2028. Including this update is well justified, as it allows the model to more accurately represent the planned commissioning timeline of the interconnector, thereby supporting more robust adequacy conclusions.

text: 4. Conclusions

text: 73 Table 3 presents ACER’s assessment of whether the differences in the AIRAA 2026-2035 base scenario, compared with the ERAA 2025 central reference scenario, are justified.

text: 74 The differences between AIRAA 2026-2035 and ERAA 2025 assessments contribute to divergent estimates of adequacy results.

text: 75 For Ireland, the most significant driver of adequacy concern in 2028 is likely the delayed commissioning of the Celtic Interconnector, now expected in April 2028.

text: 76 For Northern Ireland, the consistently higher LOLE across all target years is primarily driven by the restricted operating hours of the peaking gas-fired units, combined with the reduced wind generation due both lower installed capacity and a lower average capacity factor. Additionally, the exclusion of the second North-South Interconnector – expected to be commissioned in 2031 – further contributes to increased adequacy concerns in the years following its commissioning.

text: 77 ACER considers that most of the differences in AIRAA 2026-2035, compared with ERAA 2025 edition, are justified. However, it finds that the omission of the economic viability assessment (EVA), the inclusion of the second North-South Interconnector in the SEM assessment only, and the allocation of restricted operation hours in the base (central reference) scenario are not justified. The latter two differences primarily affect the adequacy situation in Northern Ireland, A C E R O P I N I O N N O 1 2 / 2 0 2 6 whereas the absence of EVA has implications for both Ireland and Northern Ireland systems. As set out in the previous section, ACER recommends addressing these gaps to better reflect the possible evolution of the SEM system.

text: 78 ACER recommends including a viability assessment of adequacy resources in the base scenario and ensure strong revenue consistency between the economic viability and economic dispatch modelling phases. EVA should also incorporate revenue stacking and consider demand-side units as potential expansion candidates. In addition, capacity planning – prior to the EVA stage – should account for the growth of explicit demand-side units and battery storage across all target years, reflecting rapid demand increases and renewable deployment.

text: 79 Furthermore, the assessment should (i) include the planned second North-South Interconnector (to be commissioned in 2031) in all assessments, and (ii) allocate restricted operation hours that better reflect the seasonality and duration of potential resource scarcity events.

text: 80 By implementing the recommendations set out above, ACER considers that AIRAA 2026-2035 would be on a clear path to aligning with ERAA. This Opinion is addressed to the Department of Climate, Energy and the Environment of Ireland, and to the Department for the Economy of Northern Ireland. Done at Ljubljana, on 7 May 2026. — SIGNED — V. ZULEGER, ACER Director ad interim


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identifier: ACER Opinion No 13/2013

title: ACER Opinion 13-2013 on ENTSOG's Annual Summer Supply Outlook 2013

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