As a German founder in Energy who recently moved to Spain, the recent blackout in Spain prompted me to look a bit closer at both energy markets. I will publish my observations from time to time here.
One striking difference which has puzzled me for a while has been: Why has Germany seen extremely low day-ahead electricity prices (as low as -135 €/MwH in 2024 and up to -200 €/MwH more recently ) while Spanish negative prices have been much more modest, with a historic minimum of -15€/MWh set just recently.
Why should prices even be similarly negative?This difference is especially striking considering that both countries have similarly strong wind and solar build-outs. Doing a very naive analysis and looking at the most important inflexible energy sources (i.e. those that are non-dispatchable or have to run continuously as nuclear) we even see that Spain has over 50% of its energy generation in inflexible form - much more than Germany.
Given these similarities I was especially puzzled about the differences. If anything, Spanish prices should be even more negative, given their share of inflexible, non-dispatchable generation is much higher. Yet the opposite is the case. How come? Do German producers have no cheaper way of curtailing?
I have researched a bit and while there are many reasons, three stood out to me: a) a different market design, b) different generator behavior & incentives and c) different grid topology .
Technically, markets in the EU should be harmonized, but the reality is more nuanced. EU regulation prohibits price floors, with the EU-wide SDAC limit at - 500 €/MwH.
Germany has adopted this limit around 2010, but Spain’s CNMC only allowed (!) negative prices in mid-2024. And even though the technical limit is -500 €/MwH, though CNMC/OMIE still keep a “notification threshold” at –20 €/MWh. If you were to bid lower than -20 €/MWh this triggers a regulatory review, which in practice has the effect that Spain has never seen a clearing market price of lower than -20€/MWh.
Spain’s market has another interesting quirk: They rely heavily on “complex bids”, that is bids with a minimum-income condition: Most gas & hydro units use a Minimum-Income Condition, the clearing algorithm only accepts them if total daily revenue ≥ start-up + fuel costs, so super-negative hours would not clear. In Germany on the other end, inflexible lignite/CHP units have to bid as low as needed to avoid curtailment/shutdown.
While I recognize that Spain has a different generator structure (more gas CCHP) I am a bit puzzled why OMIE opted for this market design, but maybe one of our readers can enlighten me! 🙂
With its EEG, Germany has famously kickstarted the solar industry as we know it. One negative aspect of this feed-in tariff is that it that renewables keep earning even when the price is < 0 €/MWh unless it stays negative for four consecutive hours (§ 51 EEG, the “4-hour rule”). This means that not all plants that could curtail, do curtail. On top of that, the 4-hour-rule does not at all apply to PV installations below 400kw, which is a big portion of Germany’s residential-heavy solar buildout. As a result, there is less curtailment in Germany than would be possible, further contributing to deepening the negative prices we are seeing.
In Spain on the other hand, residential solar plays a lesser role and their EEG equivalent (REER) does provide some incentive to self-curtail. On top of this the grid (REE) actively curtails bigger renewable plants through its technical-restrictions markets while Germany relies more on market mechanisms.
Spain famously is an energy island with Portugal. Interconnection to France is very limited (~3 GW) which means that foreign negative price contagion is somewhat limited (even though it could also cut another way, limiting extreme negative prices - though in reality negative prices are mostly occurring at similar times). Germany has 5x the cross-border capacity of Spain and is thus less of an energy island.
Also, Spain has ~7 GW of pumped hydro dwarfing Germany’s 2 GW. Hydro is, until massive battery storage build-out still the best technology to react to longer bouts of negative prices and therefore limits somewhat the potential of negative prices.
Obviously, the grid is congested in both Germany and Spain, with major consumption centres being away from major renewable generation centers. But at least in my research I have not found evidence that this is very different in Germany or Spain, it affects both of them similarly.
Finally, while these reasons (plus certainly many other unmentioned reasons) help explain the status quo, the more interesting question is how it will develop. Overall my assessment here would be that Spain should expect higher negative prices in the mid-term, though unlikely at German levels.
The CNMC and OMIE have already hinted that once the Bay-of-Biscay and Aragón-Pyrenees interconnectors double France-Spain capacity to ~5 GW (target 2028), and a larger share of flexible demand/storage participates, the –20 € notification trigger could be relaxed.
In the near term however, I would expect negative Spanish prices more often but not necessarily much more negative, particularly as long as the complex bid design and notification threshold are kept.
