A net exporter of energy by 2040?

Energy efficiency is both the most effective and the most overlooked response to the energy crisis and the UK’s energy import dependency. Along with the consumer benefits of cost, comfort and physical and mental wellbeing, energy efficiency ought now to be considered a priority for both energy resilience and national security. Conversely, the poor state of the UK building stock should be considered a major energy security risk which opens the UK up to the threat of any foreign power willing to use energy as a geopolitical weapon.

Another obvious solution to reduce energy imports is to focus investment on indigenous energy resources which can be harnessed at comparatively low cost using a range of renewable technologies. GB is blessed with fantastic natural energy resources which should become the mainstay of our future energy strategy. GB could massively ramp up the generation of renewable energy from indigenous resources, including offshore and onshore wind, solar and hydropower, and add in marine energy resources such as wave and tidal energy.

Maintaining the diversity of supply will, however, be critical. This means utilising a range of technologies and deploying weather-based renewables such as offshore wind across a wide range of geographies including, for example, expanding wind farms in the Celtic Sea area.

Our Net Export 2040 scenario has mirrored the ESO Consumer Transformation scenario, with renewable generation increasing from around 150 TWh in 2021 to almost 600 TWh by 2040.

Of course, there will be times when the wind doesn’t blow and the sun doesn’t shine. Conversely, there will be times when we will have an over-abundance of renewable energy which could potentially be wasted. We need the ability to store energy at scale, and the ability to both import and export energy with neighbouring energy systems.

Expanding longer duration storage and the interconnector network is critical. By 2040 we will need over 30 GW of storage capacity (not including electric vehicles with V2G potential) and over 20 GW of interconnector capacity.

Diversity is again critical; interconnectors could provide access to a wide range of energy resources and enable the UK to both import and export energy to and from markets from Ireland and North West France to Norway and Iceland, as well as to the main north European markets.

The UK has so far pursued a twin-track approach of supporting both ‘green’ hydrogen, made from domestic electricity and water, and ‘blue’ hydrogen, which would be made from increasingly imported natural gas.

Aside from the carbon emission risk of blue hydrogen, this twin-track approach is not credible given the cost and risk associated with the use of imported natural gas as a hydrogen feedstock. Many in the industry have already stated that, for reasons of cost as well as sustainability, the future will be green hydrogen. This debate should now be settled; if the UK really wants to reduce its energy import dependency, then there is no point in digging the hole deeper by using imported gas to manufacture blue hydrogen.

Our 2040 export scenario assumes that a significant amount of hydrogen will be produced in the UK using our abundant low-cost renewables. Its primary use will be in industrial processes and heavy transport, reducing the use of coal, manufactured fuels, petroleum products and fossil gas. It will also be used as a form of electricity storage, producing electricity during times when the wind isn’t blowing.

If the UK really seizes the renewables plus green hydrogen opportunity, we could even become a net hydrogen exporter by 2040.

The UK is currently the world’s largest importer of biomass (over 60 TWh in 2021), mainly in the form of pellets and wood chips coming from North America, Scandinavia and elsewhere.

There are many reasons to challenge the UK’s burning biomass as a low carbon fuel; its sustainability at scale is extremely doubtful, it has high carbon emissions from processing and transport, and the level of carbon accounting and reporting has opened the real likelihood of double counting carbon savings, especially for imported biomass. Burning biomass in the short term, on the promise of future carbon sequestration, also creates a significant timing issue which could jeopardise the goals to limit global warming to 1.5 °C, or at very most 2 °C.

Regen, and many others (including a very recent BBC Panorama investigation), no longer consider large-scale biomass to be a renewable resource. Government policy, and the recommendations made by the Climate Change Committee, now need to reconsider the role that biomass will play.

If biomass does have a role in a decarbonised energy system, it must be far more closely monitored to ensure sustainability and proper carbon accounting. It must also be targeted at areas that would otherwise be impossible to decarbonise. For example, financial support, should not be given that would encourage biomass to be used for baseload electricity generation that would displace lower cost and lower carbon renewable energy.

From an import dependency perspective, biomass has limitations. The UK could massively increase its domestic biomass production by planting new forests. Unfortunately, in our 2040 timeframe, these new forests would not be ready to make a difference. In fact, we are expecting to see a reduction in woody biomass over this time period, owing to the gap in planting that occurred during the 1980s and 1990s as a result of changes made then to inheritance taxes. If we want to see biomass use remaining at a steady state, without unsustainable imports, we will need to look at increasing the domestic production of faster-growing biomass crops such as miscanthus, willow and potentially short-rotation coppice. 

Either way, we should be reducing, and not increasing the scale of biomass combustion, and minimising imports. In our Net Export 2040 scenario, we have assumed zero biomass imports by 2040, and that all bioenergy is produced in the UK from sustainable sources.

The government’s chest-beating about unlocking the north sea flies in the face of the reality that the UK production of oil and gas is already in terminal decline.

UK gas production peaked in around 2000, at over 900 TWh per year. Around that time we were a net gas exporter. Since then, production has fallen to around 360 TWh and, with gas demand currently over 800 TWh, we are currently a significant importer of fossil gas. This has led, in part, to GB’s vulnerability in the current energy crisis. We don’t import gas directly from Russia, but we do now import a significant volume of LNG on the global market, which is both costly and higher carbon than our traditional imports from Norway and Europe.

Very high gas prices will no doubt encourage an uptick in production and may mean that fields stay viable for longer, but every assessment of future UK gas production points to a precipitous decline over the coming decades.

The North Sea Transition Authority (formerly the Oil and Gas Authority – the clue is in the name) has produced a future projection - see below -  that shows gas production falling to around 200 TWh by 2030 and less than 100 TWh by 2040. In other words, our domestic production is on a downward trajectory and will likely cease by mid-century. These NSTA projections are slightly higher than the National Grid ESO Future Energy Scenarios 2022 projections for UK gas production, but the message is essentially the same: UK gas production is in a steep decline.

The question is, if the government does increase the number of exploration licences, will this materially add to the UK gas reserves? This is very difficult to gauge. Increasing gas prices and potential tax credit support for investment may indeed increase exploration activity and the viability of previously marginal fields. On the other hand, the UK industry is in a period of decline, new development areas are increasingly difficult to bring onstream, and the co-dependency between gas fields, and oil production, may lead to an end-of-life domino effect as existing production comes to end. Either way, there is no getting away from the reality that UK gas production is in decline, and the remaining reserves will be harder and harder to develop.

To give an example, the Cambo field, which has been hailed as one of the most significant new fields in the “west of Shetland” sector, is expected to produce over 1.5 billion cubic meters of gas over 20 years .  That’s equivalent to 0.8 TWh of gas energy per year, just 0.1% of current annual gas demand.

It will take a lot of Cambos, or the discovery of much larger fields, to make a material dent in the UK’s growing gas import dependency.

The idea of fracking (hydraulic fracturing for gas) has been dug out of the policy dustbin, but judging by the response from industry, investors, and the general public it is not going to happen.

Even the terms of government support, which is based on community support, is a double edged sword which probably means that any fracking developments, and even test drilling, will face significant barriers.

The recent report by the British Geological Survey which reviewed scientific advances in shale exploration and the risk of seismic activity, suggests that very little progress has actually been made.

In any case the viability of UK fracking is extremely doubtful, even according to industry proponents like the former head of Cuadrilla. As Regen’s previous blog on the subject, Fracking Up UK Energy Policy in a Muddle, highlighted, the idea of hundreds of fracking sites across the English countryside linked by the necessary gas processing and distribution infrastructure is a fantasy.

In our 2040 Net Export Scenario we have assumed no shale gas production