Before Adding a BESS: 5 Mistakes That Can Break Your Project Economics

April 24, 2026

Spain is no longer discussing storage in abstract terms.

The updated PNIEC now targets 22.5 GW of storage by 2030, 81% renewable electricity, 34% growth in electricity demand versus 2019, and EUR308 billion of cumulative investment.

At the same time, MITECO's 2025 proposal for the next transmission planning cycle says the system is already facing requests for more than 100 GW of storage and 150 GW of solar PV.

In that context, hybridisation is not just a flexibility upgrade. It is a capital allocation decision tied to a specific node in a grid that is evolving quickly.

For IPPs, developers, and investment committees, "Should we add a battery?" is the wrong question.

The right question is whether that battery, at that specific point of connection and under that particular access regime, will improve the project's risk-adjusted returns once market capture, technical constraints, and future grid evolution are properly taken into account.

Projects usually fall short not because they chose the wrong battery technology, but because they were assessed using the wrong system assumptions.

1. Underwriting the battery with outdated arbitrage and capture-price assumptions

A common mistake is to assume that the BESS will automatically repair the merchant erosion of the renewable plant. In Spain, that assumption already needs much more scrutiny than many models give it.

CNMC published an average 2025 day-ahead plus intraday market price of EUR65.26/MWh, but the real 2025 capture coefficient for solar PV was only 0.5784. That implies an average realised market revenue of roughly EUR37.7/MWh for PV output.

A battery may still create value, but it is now being asked to solve a revenue problem that is already structurally weaker than many business cases assume.

The technical implication is important: a hybrid model built on generic spread assumptions can end up underwriting two optimistic views at once:

• That the plant will suffer limited capture erosion
• That the battery will still find wide and stable arbitrage windows

In practice, those two assumptions interact. As solar penetration rises, the plant's midday revenues weaken, while batteries increasingly compete for the same charging and discharging hours.

For that reason, the relevant unit of analysis is no longer the standalone BESS. It is the hourly co-optimised plant-plus-BESS dispatch at the point of connection.

2. Treating the existing point of connection as if it were a free option

Many hybrid projects implicitly assume that an already connected renewable plant can absorb a BESS without materially changing its operating envelope. That is often wrong.

Spain's own planning data shows that grid constraints are not a secondary issue. The 2021-2026 transmission plan allocated 27% of total investment, almost EUR1.9 billion, to integrating renewables and mitigating the restrictions that would otherwise prevent their full use.

Red Eléctrica later reported that, from May to October 2025, reinforced programming represented EUR422 million, and that in the first nine months of 2025, 0.8% of non-manageable renewable energy was not integrated for security reasons due to technical curtailment and other network restrictions.

For a hybrid asset, the practical consequence is straightforward: the battery inherits the same electrical reality as the original plant. Transformer loading, voltage behaviour, short-circuit margins, evacuation bottlenecks, neighbouring congestion, and control limitations do not disappear because a BESS is added.

In some nodes, the battery improves profile flexibility but remains trapped inside the same structural bottleneck.

A grid-aware assessment therefore has to go beyond the connection permit and the usual high-level screening. It should test the node and the surrounding network under representative operating states: spring high-PV midday, low-demand weekends, stressed voltage-control hours, and plausible future connection cases nearby.

This is exactly the type of pre-investment work for which a digital electrical model is useful. In our case, eRoots Map is designed to support that screening by combining hosting-capacity maps, future scenario modelling, curtailment forecasting, and grid visibility, so the sponsor can identify whether the BESS is truly solving a network problem or merely sitting inside it.

3. Sizing from a template instead of the node's real operating envelope

Traditional battery sizing rules, such as assigning a standard duration per MW of renewable capacity, are losing relevance. Not because duration has stopped mattering, but because the market and the grid around the asset are now evolving faster than many development cycles.

MITECO's 2030 planning proposal already points to 150 GW of solar PV requests and more than 100 GW of storage requests. In that environment, a sizing rule that looks reasonable at pre-feasibility can age badly before commercial operation if local congestion, capture prices, or neighbouring build-out move against the original assumptions.

Recent project files make the point clearly. The BOE notice for BESS Belinchon 2 describes a hybrid battery of 26.74 MW / 126 MWh, that is, a four-hour system. But the same notice explains that the plant controller at the substation must ensure that active power injected at the point of connection does not exceed the access capacity of 41.266 MWac.

That is the real lesson for sizing: useful battery size is bounded by the access envelope and plant control at the interconnection point, not only by duration templates, OEM catalogues, or CAPEX benchmarks.

In practice, sizing should be derived from four operating profiles:

• Temporal pattern of curtailment
• Local congestion pattern
• Market price profile
• Operating constraints at the point of connection

The objective is not to maximise installed MWh. It is to maximise monetisable MWh.

4. Reading the regulation too late

Another recurring mistake is to treat regulation as a final compliance check instead of a design variable.

The Spanish direction of travel is clearly more favourable to storage, but that does not mean every hybrid configuration will benefit in the same way.

The recent RDL 7/2026, approved as part of the Plan Integral de Respuesta a la Crisis en Oriente Medio, matters because it introduces flexible access so that modulated demand and storage can connect under explicit conditions of network availability. That changes how storage can be framed in access discussions and how future capacity can be unlocked.

Separately, RD 997/2025 is highly relevant for electrochemical hybridisation because it changes the project timetable in a very concrete way. The BOE notice for BESS Belinchon 2 explicitly states that, under article 6 of that decree, the hybrid storage module is exempt from simplified environmental assessment when it meets the required conditions, and that processing deadlines are cut by half.

For a developer or fund, that is not a legal footnote. It affects development calendar, permitting risk, internal approvals, and, in some cases, whether the preferred architecture is to hybridise the existing plant or structure storage differently.

The regulatory memo should therefore be written before the engineering is frozen, not after.

5. Projecting market risk, but underweighting future grid evolution

Most serious developers already model the future. The problem is not that they ignore it. The problem is that future analysis often gives far more depth to merchant price scenarios than to future grid scenarios.

Spain's recent planning cycle shows why this is dangerous. In April 2024, the current plan was modified with 73 actions and EUR489 million of investment. In July 2025, a second modification added 65 more actions and EUR750 million, focused on resilience, voltage control, and stability.

MITECO stated that these 2025 measures aim to reduce the need for technical restrictions with an estimated saving of around EUR200 million per year. Then, in September 2025, MITECO presented the proposal for the 2030 plan: EUR13.59 billion of transmission investment, 27.7 GW of new demand access from transmission instead of the 2 GW in the current plan, and expected end-of-decade renewable curtailment limited to 3.3% thanks to those reinforcements.

That is the real strategic point for hybridisation. The future is not just a price deck. It is also a changing electrical topology: more demand at some nodes, more renewable saturation at others, different voltage-control needs, new interconnection patterns, and reinforcement timing that can improve or destroy the economics of the battery.

A model that treats grid evolution as a footnote is not truly forward-looking. It is just a merchant forecast with a battery attached.

Final remark

Before adding a BESS, the investment committee should ask four technical questions:

• What merchant problem is the battery solving?
• What electrical bottleneck at the node is the BESS expected to relieve?
• What access envelope will actually govern its dispatch?
• Under which forward grid case does the project still work?

At eRoots, this is exactly how we approach the problem. eRoots Map provides a geospatial view of the Iberian grid with hosting-capacity visibility, curtailment forecasting, and a forward view of network development, while VeraGrid provides the simulation backbone for scenario analysis.

In today's Spanish market, hybridisation is not won by adding storage first. It is won by understanding the node first.