Summary of Findings
National Grid’s Future Energy Scenarios 2023 is a measured advance on the 2022 edition. It adopts a broader framing, including sectors such as aviation, shipping and rail, although these are considered primarily from an emissions perspective rather than in terms of underlying energy demand. That wider lens is welcome, though there remains scope to deepen the analysis.
The report rightly emphasises that whole-system thinking supports decarbonisation. In practice, such an approach is essential if decarbonisation is to be affordable, practical, reliable and resilient. A fragmented approach risks creating avoidable cost, operational fragility and sub-optimal investment signals.
Future Energy Scenarios 2023 Context: Recent Emissions Trends
The starting context is notable. Emissions in 2022–23 rose relative to the previous year for the first time in a decade. The unwinding of COVID lockdown effects is part of the explanation, although most restrictions had eased earlier in the year. A more structural factor appears to be the limited availability of appropriately located, naturally inertial long-duration energy storage (LDES). FES 2023 does not materially address this constraint, which raises questions about the robustness of some forward projections.
Net Zero Electricity by 2035
Future Energy Scenarios 2023 presents Net Zero Electricity by 2035 as a central objective. The ambition is commendable. However, achieving a fully decarbonised grid within that timeframe will depend heavily on the timely deployment of LDES with inherent inertia and system support capabilities. To date, strategy, regulation and market design have not provided the clarity or revenue certainty required for widespread investment in such assets. Only a small number of business models appear capable of operating profitably on a purely merchant basis in current market conditions. Without structural reform, the risk is that the resulting system may prove more expensive and less resilient than intended.
Climate Change Impacts on the Electricity System
Future Energy Scenarios 2023 appears not to assess in detail how climate change itself will affect electricity supply, demand and network performance. Changing weather patterns will influence generation profiles, peak demand characteristics and infrastructure stress. These factors have implications for technology selection, network topology and resilience planning, yet receive limited attention.
Demand Analysis and Excluded Loads
The demand analysis in FES 2023 explicitly excludes additional electricity required for upstream primary energy production and conversion losses associated with fuels such as hydrogen. Including these factors could more than double electricity demand in certain scenarios. Such differences would materially affect supply requirements, transmission and distribution planning, and system operation. Omitting them reduces the usefulness of the scenarios for long-term planning.
Negative Emissions and Carbon Capture
The report appropriately recognises that the electricity system may need to become net negative by 2050 to offset hard-to-abate sectors such as aviation and agriculture. The principal engineered approaches considered are Bioenergy with Carbon Capture and Storage (BECCS) and Direct Air Capture (DAC), alongside nature-based solutions such as reafforestation and seagrass planting. DAC remains nascent but potentially promising; carbon capture for power generation is more mature but faces practical and economic constraints.
Carbon capture and storage (CCS) is often treated as carbon neutral, yet capture rates are below 100%, even before supply-chain emissions are considered. Residual emissions can be substantial. At the Boundary Dam project, for example, effective capture rates have frequently been reported at levels implying significant remaining emissions, while performance data for other installations is often limited. Furthermore, the “use” component in CCUS represents a temporal deferral of emissions rather than permanent abatement, and can be susceptible to double counting if not carefully accounted for.
Both BECCS and DAC are energy-intensive and costly, and their deployment must also address supply-chain emissions. Biomass availability for BECCS is constrained by land and food system considerations. Consequently, a prudent strategy would seek to minimise the requirement for negative-emissions technologies by limiting reliance on CCS-equipped fossil generation, avoiding unabated generation, and prioritising genuinely zero-carbon generation and storage. FES 2023 continues to incorporate substantial CCS generation and some unabated capacity, which increases reliance on future negative-emissions deployment.
Electricity Storage Requirements
Even under modelling assumptions that appear to understate overall need, Net Zero-compliant scenarios require 33–52 GW and 116–197 GWh of storage. This implies an average duration of approximately 3.5–3.8 hours. Given that most battery installations are 1–2 hours in duration, a material proportion of longer-duration storage—4 to 12 hours or more—would be required. Durations below four hours are unlikely to sustain supply through evening peaks and overnight, let alone extended low-wind, low-solar events (Dunkelflaute). The inclusion of Dunkelflaute analysis is a constructive step, though it still assumes imports, may underestimate correlations with continental weather systems, and does not fully consider sequential low-generation events.
Hydrogen Demand and Storage
Hydrogen demand is identified at up to 431 TWh across scenarios, despite the exclusion of several major potential applications such as certain industrial processes, synthetic fuels and ammonia production. Inclusion of these uses would significantly increase projected hydrogen demand, even if some less likely uses were removed. Forecast storage requirements of 29–46 days’ consumption translate into tens, and potentially hundreds, of TWh as demand scales. This is a substantial infrastructure and storage challenge.
Consumers and Cost Allocation
The focus on consumers remains prominent. However, without explicit time horizons, an emphasis on least-cost options today can disadvantage medium- and long-term optimisation. Moreover, generation costs now comprise roughly 20–25% of retail electricity bills, down from 75–80% a decade ago, with network charges, levies and system costs forming a growing share. A narrow focus on short-term energy prices risks overlooking the structural drivers of total system cost.
Policy and Delivery
The Policy and Delivery sections concentrate heavily on demand-side measures, energy efficiency and heat electrification. While these are important, they address only part of the system challenge. Generation adequacy, storage, transmission and distribution architecture, integrated system planning, reliability and resilience require equal attention. A strong demand-side emphasis should not displace the responsibility to ensure sufficiency and security of supply.
Digitalisation and Consumer Behaviour
Digitalisation can optimise system operation but does not create additional firm capacity or resilience. While consumer engagement tools, such as smart metering and smart charging, offer incremental benefits, their aggregate impact on bills and peak demand is relatively modest when set against overall system cost pressures. Behavioural assumptions embedded in savings projections may also prove optimistic.
Markets, Flexibility and Duration
There remains a strong emphasis on short-duration, demand-side flexibility. Duration, however, is a critical parameter. Contracts for short-duration storage can erode the revenue stack for long-duration storage, which provides capabilities—such as extended energy shifting and inertial support—that batteries cannot replicate at scale. Without explicit mechanisms valuing duration and system services, investment in LDES may remain insufficient. An exclusive focus on flexibility also risks under-emphasising grid stability, reliability and resilience.
Locational Signals and Regionalisation
Enhanced locational pricing signals are proposed. While locational efficiency has merit, excessive granularity could fragment a 50–100 GW national market into numerous small sub-markets, disadvantaging large, capital-intensive projects such as offshore wind and large-scale LDES, which are inherently location-constrained. Overly dynamic locational incentives may also increase investor uncertainty, particularly in a high-volume, low-margin sector.
System Operation Costs and Offshore Wind Integration
System operation costs have risen sharply since renewable penetration crossed certain thresholds. This reflects the interaction of intermittent generation, limited storage and current market design. Offshore wind expansion also necessitates significant onshore reinforcement and ongoing operational expenditure. FES 2023 does not fully analyse how alternative system architectures might mitigate these costs.
Whole-System Planning and Inter-Seasonal Storage
Whole-system planning, as reflected in National Grid’s Pathways to 2030 Holistic Network Design, signals progress. However, the report appears oriented toward relatively short-term objectives. Inter-seasonal storage is treated as an assumed requirement, yet intermediate-duration storage (four hours to several weeks), quantitative assessment of seasonal need, and mechanisms to incentivise strategic reserve receive limited elaboration. By comparison, continental European gas systems typically maintain reserves equivalent to several months of consumption, whereas the UK has substantially less.
Grid Network Capacity
Grid analysis is incorporated into FES for the first time, which is a significant improvement. However, the projected doubling of grid capacity may understate requirements under current regulatory and market structures; some forecasts anticipate more than tripling. If hydrogen production were fully integrated, requirements could increase further. Alternative configurations, such as coupling renewables with co-located LDES or siting elements of the hydrogen economy off-grid, could materially reduce reinforcement needs and associated capital and operational expenditure, yet are not explored in depth.
A Fair Transition to Net Zero
A fair transition depends on affordability, reliability and resilience alongside decarbonisation. Achieving this requires medium- and long-term system optimisation, deployment of large-scale, multi-capability assets, and mechanisms to share system-wide benefits across projects.
Closing Thoughts
The transition requires replacing hydrocarbons with zero-emissions technologies capable of delivering energy, dispatchability, stability, resilience, security of supply and black start capability. Conventional power stations provide these attributes concurrently; Net Zero technologies must replicate them at comparable scale. Absent sufficient large-scale, long-duration, naturally inertial storage and appropriate regulatory frameworks, progress in carbon intensity reduction may stall. Historical trends suggest decarbonisation is not linear, and recent data indicate a potential plateau. Future Energy Scenarios 2023 raises legitimate questions about whether current trajectories are sufficient to meet Net Zero objectives, particularly a fully decarbonised power sector by 2035.
First published 2023
