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Renewable energy developers in the UK face a growing challenge: an increasing proportion of their generation is being curtailed due to grid constraints.
This is especially acute in Scotland, where wind energy makes up over 80% of the 15GW of total connected generation, with a further 26GW in planning and development. At the same time, industrial sectors must rapidly decarbonise, both to meet climate policy targets and to maintain market position in an increasingly competitive consumer landscape where reducing carbon emissions is becoming a supply chain requirement. This situation has been steadily increasing over a number of years, in the article we examine whether this mismatch between renewable energy supply and industrial demand finally tips the balance for one of the key discussion topics of the last few years – green hydrogen production.
Over the past few years, developers have toyed with the idea of hydrogen production, and numerous feasibility studies have been undertaken, but very few projects have reached FID. This is because, at the moment, green hydrogen is expensive to produce, and it has been challenging to secure offtakers at these costs. The Hydrogen Allocation Round (HAR) price level in December 2023 came in at £241/MWh, or roughly £8/kg. To reach cost parity against industrial gas, the delivered price would need to be closer to £2/kg (though this target fluctuates depending on global gas prices). As electricity is a considerable cost in the production of green hydrogen, making use of cost-effective energy production will be essential in making these business models viable moving forward.
By converting curtailed wind power into hydrogen, could developers reduce constraint costs while providing industry with a scalable, low-carbon alternative to fossil fuels? Could this enable greater utilisation of Scotland’s renewable resources while addressing industrial decarbonisation challenges? If so, what are the opportunities and the challenges?
Grid constraints and renewable curtailment in Scotland
A key barrier to both the development of renewable energy projects and viable hydrogen production is the availability of grid connection capacity. It is common for developers to be offered grid connection dates into the 2030s – far longer than most organisations can or are willing to wait.
Additionally, assets that do secure grid connections often come with active network management or curtailment conditions, meaning they can be switched off if there is excess generation in the network. National Grid ESO has calculated that by 2035, the level of curtailment could rise from 4.3TWh in 2023 to 58TWh in 2035.
Furthermore, if a site is on a variable PPA or CfD contract, it may enter periods of negative pricing when there is either an excess of generation or excessive imports. In 2022, there were 19 hours of negative pricing, but this rose to 139 hours in 2024 (1.6% of the year). The impact of this will be significant as these periods typically coincide with high renewable generation.
Through recent EETF funding, Locogen has modelled whether curtailed energy could be viably used for hydrogen production under different scenarios. The conclusion was that it is not viable to run a plant solely on curtailed energy. However, in cases where curtailment is significant or expected to grow, using curtailed energy as a partial input can successfully reduce the Levelised Cost of Hydrogen (LCOH), improving competitiveness.
Grid reforms, locational pricing, and cost reduction
One of the key considerations for developers of renewable projects in Scotland is the impact of Transmission Network Use of System (TNUoS) charges. These charges are location-dependent, resulting in higher fees for generators situated farther from demand centres, such as those in Scotland. This structure has significant implications for renewable energy projects:
- Higher costs: Generators in Scotland incur substantially higher TNUoS charges compared to those in other parts of the UK. For instance, in the 2021/2022 period, Scottish generators paid approximately £26.4 per kW, while counterparts in West Devon and Cornwall received payments of £3.76 per kW. This disparity makes Scottish projects less competitive and can deter investment.
- Volatility and unpredictability: The fluctuating nature of TNUoS charges adds financial uncertainty, complicating the planning and financing of renewable projects. This unpredictability can hinder the commercial viability of projects and affect long-term investment decisions.
In response to these concerns, Ofgem has acknowledged the issues and, as of late 2023, has been consulting on potential reforms, including temporary adjustments to TNUoS structures. While a cap and floor mechanism has been proposed as an interim relief measure, no final decision has been made.
To address the wider capacity and connection challenges experienced nationally, National Grid ESO has launched Connections Process 2030 (CP2030), a reform initiative aimed at accelerating grid connections. CP2030 prioritises projects that are further advanced and able to connect sooner. While these changes are welcome, they also introduce uncertainty as new prioritisation frameworks are developed and implemented.
In addition to physical infrastructure changes, recent studies, including the recently issued Splitting the Difference report (Hydrogen UK, RenewableUK), highlight the role of electricity market reforms in improving cost-effectiveness for hydrogen production in Scotland. Key potential developments include:
- Locational pricing: Moving towards zonal or nodal electricity pricing could lower costs in Scotland, where high renewable penetration results in surplus generation and lower wholesale prices.
- Incentivising electrolysis during curtailment events: Policies allowing electrolysers to access curtailed electricity at reduced costs could significantly lower the LCOH.
- Network tariff reform: Adjusting TNUoS charges to better reflect the system benefits of hydrogen electrolysis could make Scotland a more attractive investment location.
- Integration with the hydrogen backbone: The UK government is exploring a hydrogen transmission network linking Scotland to industrial clusters in England and Wales. While early-stage discussions are promising, firm commitments and timelines are still under development.
- Flexible demand markets: Creating incentives for industries to adopt hydrogen during times of excess renewable supply could help balance the grid and further drive down energy costs.
While these potential reforms set the scene for an improved marketplace, they remain in consultation stages and are unlikely to provide immediate certainty for investment decisions.
The opportunity for Scotland as a hydrogen powerhouse
Based on the current issues with curtailment and the future opportunities that may arise from locational grid changes, Scotland has the potential to become a major, cost-effective producer of green hydrogen, provided the right policy and infrastructure changes occur. With its abundant wind resources, increasing curtailment, and a policy-driven push toward decarbonisation, Scotland is uniquely positioned to lead the UK’s hydrogen economy.
To capitalise on this opportunity, the following key actions are necessary:
- Market reforms to enable hydrogen producers to access curtailed electricity at competitive prices.
- Expansion of the hydrogen transportation network to facilitate large-scale hydrogen distribution.
- Targeted incentives for industrial hydrogen adoption, ensuring demand aligns with supply growth.
- Integration with broader energy systems, ensuring hydrogen supports rather than competes with direct electrification efforts.
Offtaker limitations and risks
The key residual risk with any hydrogen development, outwith the cost of energy and availability of water supply (two essentials in any system planning) is the long term offtaker contract. This is currently the most challenging aspect, and the stage that has caused so many of the current projects to be put on hold. The high cost of green hydrogen, and the ability to effectively transport it to the end user mean that the risks remain of stranded assets as the demand and distribution parts of the hydrogen economy develop. A number of operators are keen on the potential for hydrogen backbone infrastructure to transport and distribute hydrogen, but any national guidance and steer on this is several years away from being clarified. This is why some operators, such as Storterra are developing their own dedicated infrastructure to connect their offtakers without the need for extensive transportation infrastructure.
The other key consideration relates to the ability for offtakers to transfer their plant to hydrogen use. Currently we have a situation where each site, each process, is having to run their own specific site-based tests on the viability of adaptation, and this is intensive and costly and limits uptake to a few larger offtakers. However, this will improve as familiarity and the number of case studies improve, but it definitely creates an additional technical and financial hurdle to first stage uptakers.
A strategic opportunity for Scotland
Hydrogen presents a strategic opportunity for developers looking to enhance energy resilience, cut emissions, and manage rising energy costs in Scotland. By leveraging abundant renewable resources, aligning with policy frameworks, and benefiting from emerging grid reforms, Scotland can position itself as a leader in the hydrogen economy, creating economic and environmental benefits that extend beyond national borders.
If properly supported, Scotland has the potential to emerge as a European hydrogen powerhouse, transforming excess renewable generation into an exportable, value-added energy commodity.
Learn more about how we can support you with your hydrogen projects.
