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Risk management is essential to a thriving green hydrogen market

In anticipation of RenewableUK's Green Hydrogen event in Liverpool on 18th April, Dan Brimelow, Statkraft’s Commercial Manager, Origination in the UK, examines how trading structures may develop in order to drive a successful new market for green hydrogen in the UK. 


Green hydrogen is the key next step to net zero. It enables us to store surplus wind and solar and convert it to heat, transport or power for later on at peak times when it’s most needed. Hydrogen economics are expected to significantly improve as our industry learns more about manufacturing electrolysis plants, and we can expect to see several GWs built in the next decade.  


Statkraft’s trading business is excited about playing a big part in supporting green hydrogen projects in the UK. We are the leading player in green energy transition trading with a customer business of 4.3 GW of long-term renewables and 2 GW of firm flexible power. Hydrogen has strong synergies with both businesses; Statkraft will enable hydrogen projects to be realised by trading the electrolysers effectively and by providing long term fixes and floors that underwrite bank debt.  


The Government’s Low Carbon Hydrogen Agreement (LCHA) effectively demands a 15-year fixed power price – this can only be offered by backers with a strong credit and a large appetite for risk. For example, over its lifetime a 25MW electrolyser will be taking £200m of risk downstream via the sale of the energy and £100m of risk in the upstream purchase. This makes hydrogen an attractive hedge for Infrastructure Funds with existing renewable assets, able to protect against falling gas prices, or protect from falling prices that come with increased renewable deployment.


The key drivers of green hydrogen are power costs and electrolyser capex. It’s essential that the end customer of the hydrogen is supported so they can choose to run an electrolyser when power prices are expected to be at their lowest. In many cases the customer will have the option to burn natural gas instead of hydrogen if it saves them money. This means that there will be an interaction between the spot price of power going into the electrolyser to make hydrogen and the spot price of the natural gas the customer might burn instead. Running the electrolysers at a medium load factor can save 10% of power price in 2025, growing to 20% over 7 years. At much lower load factors, in the future, when capex has decreased significantly, the discount could be as high as 50% by 2032. This shows how crucial it is to work with the end user to access this flexibility.  

 

Statkraft also recognises that the benefits of selling power from a portfolio of renewable power projects to electrolysers are compelling compared to an electrolyser tied to a single project. If we consider that a 100 MW wind farm supplying a 20 MW electrolyser would have a shortfall of power 35% of the time, the merchant risk of this over the 15 years of the LCHA agreement could entirely wipe out their capex of around £24million or double their money. By not relying on a single power supply only, you remove the need for complex and expensive electrolysers. Statkraft and other traders are able to add value to the hydrogen market by taking such an approach, which supports independent developers of electrolysers in particular.

 

The power from electrolysers needs continuous optimisation. This will allow the end customer to buy at low spot prices in the Day-Ahead market, especially overnight, and avoid Peak times and prices. The Day-Ahead to Within-Day position can then be re-traded. For example, if prices go up in the Within-Day market enough, the power that was purchased can be sold and the hydrogen generators can be paused until the power prices fall again. In the meantime the customer can draw from cheaper energy alternatives. Re-trading like this adds value, which increases with price volatility. There is also a longer-term issue. If spark prices, the difference between power and gas prices, increase substantially, then unless a project has hedged its power long term, it may be necessary to pause hydrogen generation. Therefore, most end users will still require the capability to run on natural gas as backup when the electrolyser isn’t available. 


The Statkraft team has identified a number of ways of structuring the risk to the electrolyser between the upstream purchase and downstream sale. The purchaser, who is buying the power as it’s produced (known as PaP), has the risk of unpredictable renewable generation and not knowing how much power will be available. While downstream there is risk of not being able to predict consumption and demand. Alternative structures include traders fixing PaP risk, they can provide a floor of the difference between upstream and downstream spot prices, or take a share for optimising the difference.

 

In the last year, the Upstream hedge from an existing asset is becoming progressively more expensive as the capex for wind turbines and solar has increased and interest rates have also gone up. At the same time the forward curve for trading power has reduced. This may drive developers in Hydrogen Allocation Round 2 to more flexible hedging structures to manage power merchant risk rather than fixing all their power price up front.


It is too early to see what the winning business models and trading structures are for this exciting new hydrogen market. But Statkraft is positioned well, already managing the largest flex portfolio in the UK. We will be a big part of driving a successful model, enabling customers to get their hydrogen projects financed and running well.  

 

To find out more, drop me a line at Dan.Brimelow@statkraft.com or visit our website What we offer (statkraft.co.uk) 


Dan Brimelow, Commercial Manager, Customers Facing Business, UK & Ireland 

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