Post - Blog
What rising grid constraints mean for the UK energy sector
- a day ago (2026-10-22)
- Junior Isles
James Clark , Business Development Manager at SmartestEnergy
EP Shangahi 2026
Annual grid constraint costs continue to rise, with NESO’s worst case projection indicating they could reach £7.4bn by 2030, compared with around £1.8bn in 2025. For the UK energy sector, this steep trajectory means higher household and business energy bills and more operational uncertainty for developers.
The core issue is network congestion. While renewable generation capacity is expanding rapidly across Britain, the physical grid lacks capacity to carry electricity from generation hotspots to high-demand regions. Limited transmission capacity can make it hard to move electricity from generation-rich areas to major demand centres, resulting in renewable curtailment and higher system costs.
To help address these bottlenecks the government has announced Great British Grid, a new publicly owned body within Great British Energy intended to support investment in network infrastructure alongside private capital, accelerate strategic grid upgrades and help deliver faster connections to the electricity network.
New infrastructure, for example physical transmission upgrades such as high-voltage pylons, subsea cables and substations, take years to convert into grid capacity, and constraint costs are already being incurred. That’s why it’s important to get more out of existing assets through better storage dispatch, demand flexibility and improved network availability – to help reduce costs while larger grid upgrades are delivered.
What developers are up against
For developers and asset owners, grid bottlenecks can create financial friction long before a project generates its first megawatt-hour. In many areas, available connection capacity is already taken, so target connection dates can be delayed, leaving capital tied up and development costs accumulating before the asset earns revenue. As a result, for many projects, network availability and connection timing are becoming as important to project economics as the underlying generation resource. Policy uncertainty and market-design uncertainty have compounded this issue.
Reformed national pricing
The government has opted to maintain a single national wholesale electricity price under Reformed National Pricing (RNP), ruling out a shift to zonal pricing. While this preserves the wholesale market and provides developers and buyers with stability, location signals are expected to become increasingly important through reforms to network charging, connection rules and the Strategic Spatial Energy Plan (SSEP). Final decisions on those siting levers are due by the end of 2026, while the final SSEP is expected in autumn 2027. This means the coming months are the time to stress-test project pipelines against possible changes.
Protecting clean power contracts
For corporate buyers and generators, the practical question is who carries the risk. A government-backed Contract for Difference (CfD) helps stabilise revenues against wholesale market price volatility, but it does not itself provide a route to market or remove balancing and grid constraint risk. The project will normally still require a Power Purchase Agreement (PPA) with a supplier or trader to sell its output and manage route-to-market and balancing exposure.
Grid constraints can still affect project revenues because CfD support is linked to generation volumes, while the interaction between constraint payments and CfD settlement can be complex. Balancing costs can also still sit with the generator or offtaker depending on the contract.
To mitigate these risks, PPAs should clearly allocate balancing, shaping, curtailment and associated revenue risk. Parties should agree whether balancing charges are fixed within the contract price, passed through at cost, or capped to limit exposure to unexpectedly high balancing costs. Curtailment provisions should also clearly establish how lost output, associated revenues and any constraint compensation are treated between the parties.
Contracts should allow for changes in the rules, to respond to RNP decisions and the SSEP as those measures are developed and implemented. As the UK works towards its 2030 clean power goals, PPAs should retain sufficient flexibility to respond to changes in market, charging and connection arrangements as the RNP framework and SSEP are implemented.
Innovative commercial structures demonstrate how these risks can be managed in practice. For instance, our work with OurCoop shows this in action, where five independent co-operatives pooled their demand into a 10-year corporate PPA spanning over 400 sites, giving smaller buyers access to long-term renewable supply through an innovative commercial structure.
Grid reform will take time, but the constraint bill will not wait. Developers, asset owners and energy buyers should focus on what can be controlled now.