One thing I'm not clear on: "The loss of supported generation could result in the need for higher strike prices to compensate."
I interpret this to mean that project developers/owners would need higher strike prices for their projects to be economically viable. This seems true. But how would higher strike prices be achieved?
* Would strike prices be mandated by regulation? If so, would this be different than feed in tariffs?
* Would operators need to withhold production below their required strike price? If so, wouldn't this approach be vulnerable to "defection" by other operators? If marginal production cost is zero, why wouldn't every operator provide power at any price higher than zero?
* Would we depend on the market to provide higher (average) strike prices? Wouldn't this imply less surplus generation capacity, potentially leading to blackouts during periods of peak demand?
Empirically, there is little to argue with. Problems start with the narrative/analysis at the end. Negative prices occur because renewables (CAPEX-based) are forced into a marginal market which suits OPEX-based systems. Marginal markets are treated in a quasi-religious way ("our market which art in heaven" etc) instead of an objective way. To some extent, this is understandable if you are a trader & rely on market volatility to make money - at all costs you want to keep markeginal markets going - regardless of their suitability or lack thereof for CAPEX-based system. However, a failure to recognise this reality, leads to a situation where the assumption is that modest changes to marginal markets can fix the situation. The other failure in the analysis is that as the amount of renewable increases - so do surpluses - in a non-linear fashion. This is not an assertion but can be proved - for just about any size of system (regional or national). In terms of the solutions offered - not attempt is made to consider scalability. For example, which systems at a national level (or local level) offer the possibility to store 200GWh - 500GWh of electicity (national) or 3MWh (locally). If Germany hits some of its targets for RES, these are the sort of national surpluses it will face post 2030. Batteries have a minor role to play - electrolysers have a major role. The problem is that on the one hand RES only gets funded if the flow of revenue is certain, on the other hand it is proposed to use "market mechanisms" (we will incentivse things) to pull on RES. Remind me how well market mechs have worked so far? Well they haven't because they can't. Energy transformations are engineered (horse) - markets are then used for cost optimisation purposes (cart) - once the transition is made. Currently we have the cart (markets) standing in front of the horse (engineered transition) and we are wondering why nothing is happening.
Could you explain how solar capacity which is not participating in the market (FiT, behind the meter self consumption) does contribute to the lower market prices. I guess it lowers the demand, because they are not providing supply, as they are not actively bidding on the market. Then again, how can hundreds of thousands of small scale solar PV under FIT and self-consumption be reasonably accounted for in the day-ahead forecasts and ultimately make up the supply/demand curve?
What would happen in the extreme case where 500 GW of small scale solar were to be installed only behind the meter for the self consumption? How would that contribute to the market prices besides obviously lowering the demand?
Just a suggestion, as this part is a bit confusing: "The graph shows that, as of the end of September 2024, the number of hours with negative prices is roughly the same as the number of hours with prices below 10 €/MWh, both around 400 hours."
It should read "The graph shows that, as of the end of September 2024, the number of hours with negative prices in 2024 is roughly the same as the number of hours with prices below 10 €/MWh in 2023, both around 400 hours."
I have no idea: How many MWh are sold over epex? at hourly prices? And how many OTC/PPA?
this gives a reference of the magnitude
This is very informative. Thanks!
One thing I'm not clear on: "The loss of supported generation could result in the need for higher strike prices to compensate."
I interpret this to mean that project developers/owners would need higher strike prices for their projects to be economically viable. This seems true. But how would higher strike prices be achieved?
* Would strike prices be mandated by regulation? If so, would this be different than feed in tariffs?
* Would operators need to withhold production below their required strike price? If so, wouldn't this approach be vulnerable to "defection" by other operators? If marginal production cost is zero, why wouldn't every operator provide power at any price higher than zero?
* Would we depend on the market to provide higher (average) strike prices? Wouldn't this imply less surplus generation capacity, potentially leading to blackouts during periods of peak demand?
Or am I missing something?
Empirically, there is little to argue with. Problems start with the narrative/analysis at the end. Negative prices occur because renewables (CAPEX-based) are forced into a marginal market which suits OPEX-based systems. Marginal markets are treated in a quasi-religious way ("our market which art in heaven" etc) instead of an objective way. To some extent, this is understandable if you are a trader & rely on market volatility to make money - at all costs you want to keep markeginal markets going - regardless of their suitability or lack thereof for CAPEX-based system. However, a failure to recognise this reality, leads to a situation where the assumption is that modest changes to marginal markets can fix the situation. The other failure in the analysis is that as the amount of renewable increases - so do surpluses - in a non-linear fashion. This is not an assertion but can be proved - for just about any size of system (regional or national). In terms of the solutions offered - not attempt is made to consider scalability. For example, which systems at a national level (or local level) offer the possibility to store 200GWh - 500GWh of electicity (national) or 3MWh (locally). If Germany hits some of its targets for RES, these are the sort of national surpluses it will face post 2030. Batteries have a minor role to play - electrolysers have a major role. The problem is that on the one hand RES only gets funded if the flow of revenue is certain, on the other hand it is proposed to use "market mechanisms" (we will incentivse things) to pull on RES. Remind me how well market mechs have worked so far? Well they haven't because they can't. Energy transformations are engineered (horse) - markets are then used for cost optimisation purposes (cart) - once the transition is made. Currently we have the cart (markets) standing in front of the horse (engineered transition) and we are wondering why nothing is happening.
Could you explain how solar capacity which is not participating in the market (FiT, behind the meter self consumption) does contribute to the lower market prices. I guess it lowers the demand, because they are not providing supply, as they are not actively bidding on the market. Then again, how can hundreds of thousands of small scale solar PV under FIT and self-consumption be reasonably accounted for in the day-ahead forecasts and ultimately make up the supply/demand curve?
What would happen in the extreme case where 500 GW of small scale solar were to be installed only behind the meter for the self consumption? How would that contribute to the market prices besides obviously lowering the demand?
Thanks for the fantastic work you do!
M
Just a suggestion, as this part is a bit confusing: "The graph shows that, as of the end of September 2024, the number of hours with negative prices is roughly the same as the number of hours with prices below 10 €/MWh, both around 400 hours."
It should read "The graph shows that, as of the end of September 2024, the number of hours with negative prices in 2024 is roughly the same as the number of hours with prices below 10 €/MWh in 2023, both around 400 hours."