Why do victims of shark attacks tend to eat ice cream beforehand, and what does this mean for UK solar investors?  

The relevance of this to renewable investing is, of course, the latter, the impact of hot weather on electricity prices. On Tuesday, 5 August 2025, a summer day, we saw the average UK day-ahead wholesale electricity price dramatically fall. It dropped from its normal range of GBP 54 MWh to GBP 76 MWh, a year-to-date low of GBP 16.79/MWh. This was mainly due to the unpredictable British weather; it was fairly sunny, and the country was still experiencing the effect of storm Floris, which had hit the mainland the previous day. Interestingly, the UK’s wind speed record for August was also set in Wick on that day when wind speeds reached 82 mph.  

Earlier this year, during the May 2025 bank holiday, it was again warm and windy. Day-ahead wholesale prices dipped to GBP 52/MWh. However, this time with a one-off record low of minus (GBP 35.18) per megawatt-hour. That weekend, the National Grid ESO paid wind generators GBP 50 million not to produce due to capacity issues in Scotland. whilst solar output reached a record 14 GW, almost half of the total demand. There were no records of shark attacks, though.  

This is all very interesting if you are a weather, shark, or ice cream nerd. But it also starkly illustrates the link between day-ahead pricing and the weather. This impact will get more pronounced as we add more weather-dependent capacity to the system.  

The UK Contracts for Difference (CfD) regime protects some developers from these risks because the Treasury covers the shortfall between the day-ahead price and the CfD strike price. However, and here’s the nub of the issue: If the day-ahead market reference price is negative for six or more consecutive hours, the CfD won’t pay out during that period. 

Furthermore, only around 18.5% of solar capacity in the UK has a CfD. The other 81.5% risk negative prices pretty much every day when it is simultaneously sunny and windy.  

And days with negative hourly prices are increasing.  In 2024, the UK recorded at least 149 hours of negative electricity prices. This is five times more than the 29 hours in 2022. Albeit most of these hours occurred in the middle of the night, driven by wind energy, not solar. In May 2025, the N2EX day-ahead power market experienced a record of 17 consecutive hours of negative pricing. This event tied the previous record set in July 2023. 

We see this more starkly in Germany, where in the summer of 2025, Germany recorded negative prices in 345 out of 2,184 daylight hours. The lowest price during this time was minus (GBP 250.32/MWh), recorded between 1:00 PM and 2:00 PM on Sunday, 11th May. Also, around 28% of Germany’s solar generation in the first five months of 2025 happened when prices were negative. This is an increase from 18% during the same period in 2024.  

And this is before we layer on growth. The UK currently has 20 GW of solar capacity. There’s a plan to reach 70 GW by 2035. This would require an investment of about GBP 30 billion based on 2025 prices. However, there are only 3 GW of batteries to time shift generation, so daytime summer supply will most likely triple within the next ten years, and this is invariably going to increase the number of days with negative pricing.  

Stress-Test: What Negative Prices Do to IRRs and DSCRs 

So, what does this mean for project economics and the bankability of a solar project?   

Let’s take a typical 50 MW merchant solar farm in southern England and assume the following metrics: 

• Capex: ~GBP 30 M (≈ GBP 600/kW installed)

• Capacity factor: ~960 hours, so 48 GWh  

• Base case merchant capture price: GBP 50/MWh → 

• Annual revenue ≈ =GBP 2.96 M

• Opex: GBP 10/kW/yr → ≈ GBP 0.5 M/year

• EBITDA base case: ≈ GBP 2.4 M

• Gearing at 65%, so GBP 19 M of debt and GBP 11 M of equity 

• Minimum DSCR: ~1.2x, post-tax equity IRR 10.05% 

This all sounds ok, 10% equity IRR is not fantastic, but it’s not a disaster, and the sun shines every day, so it is a pretty low-risk investment.  

Now let’s layer in negative price scenarios as all that extra capacity starts to appear on the grid. 

This is why lenders are twitchy about negative price risk. Projects with low levels of gearing at 65% are still at risk. Negative prices can lead to revenue loss. Even 144 hours, or about two weeks in summer, can drop DSCR ratios below 1. As we saw above, Germany had 345 hours of negative prices in summer 2025. So, 144 hours in the UK seems possible, especially if we triple the amount of installed solar capacity.   

How to mitigate this (apart from not going into the water) 

This is scary stuff for solar investors, but the more canny are learning to structure the risk.  

• PPAs with robust floors – a good, solid corporate PPA with a floor price decoupled from the day-ahead price is probably a better and more bankable bet than a CFD 

• Solar plus storage hybrids – having access to batteries enables the SPV to time shift some of the production to the evening period when prices rise. However, this benefit is limited by the capacity of the battery, and as hybrid systems become more common, their impact will lessen.  

• Geographical diversification – negative prices tend to affect specific markets, so a pan-European portfolio can lower that risk. This, of course, is easy to say, harder to do 

• Policy engagement is important – if negative prices stop investment, we might need to change the CFD, or wholesale market. However, that isn’t the most compelling argument for a bank 

In conclusion, shark attacks in the UK are pretty rare. Someone got bitten in 2022, but they were actively putting bait into the water to try and attract sharks whilst simultaneously snorkelling. So, you can’t legislate for stupidity. Negative prices are also rare but unfortunately increasing. Banks remain strong supporters of UK solar. However, I suspect the issue of negative pricing is now showing up in some risk assessments. If the UK succeeds in tripling its solar capacity from 20 GW to 70 GW, the number of daytime negative hours will inevitably increase, but this just may act as a self-regulating brake on installation.  

My theory is simple: When negative daytime prices in summer exceed 100, new standalone solar projects probably become unbankable. This means the rate of increase in capacity will diminish, and the number of negative hours will plateau around 100. Existing projects may be able to survive, but they’ll face tighter cover ratios and lower returns. It’s unclear how many GW of extra capacity will trigger this 100-hour inflexion point. But it will likely be far less than 70 GW unless demand radically increases. The risk is that the government’s solar target might not be met. This could happen if no new projects get funding after hitting the 100-hour negative price point.  My best estimate is that the market can absorb perhaps another 10 GW before negative prices really start to inhibit investment, but that’s just a guess.   

This trigger point could be mitigated by amending the CFD regulations to compensate solar farms for negative prices. This is technically achievable, but getting public support for compensating generators during negative prices will be much harder. Without that support, it’s hard to see how GBP 30 billion in new capacity gets funded. We can confidently say that shark attacks in UK waters will stay rare. However, we are far less certain that 70 GW of solar will eventually be developed on the land.