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Time to discuss the death of the gas grid

  • Neither hydrogen nor biomethane are likely to save the gas distribution grid from obsolescence. One will be too expensive, the other too hard to scale 
  • However, unless the government steps in force change, households will continue to use natural gas for heating for decades
  • Even if decommissioning is years away, the government and regulator need to start grappling with the problem now. The potential liability is enormous and unfunded
  • There are no straightforward options for how to manage decline and decommissioning. But the consumers, grid operators and investors need consistency and transparency. At present, there is little of either

Stretching across the length and breadth of Britain is a natural gas grid network some 284,000 km in length and valued – from a regulatory perspective – at around £26 billion.

Since its creation over 50 years ago the grid has avoided millions of tonnes of CO2, by replacing coal and town gas. It has also brought reliable, affordable warmth to millions of households. 

But in a few decades, we may simply not need it anymore. 

The expectation is that the energy transition and the electrification of heating will prompt a steady decline in gas demand and the gas customer base. If left unaddressed, the grid will – at some point – become uneconomic to run. But there is no precedent for retiring vast chunks of privately owned infrastructure, and the government has yet to fully engage with the issue. 

This framing of the gas grid as destined for decommissioning is not, however, straightforward. 

Hydrogen alternative

If the quest for net zero means natural gas use has to fall, grid operators would understandably like to see their assets used for something else. Several have pushed the idea of hydrogen for home heating, which would keep the low-pressure distribution part of the grid alive. But this now looks unlikely. 

The only remaining village trial for green hydrogen heating was cancelled late last year. Public opposition has been vocal. Even if the public were more receptive, hydrogen will almost certainly be too expensive as a residential heating option. The government’s own consultation on Future Homes and Buildings Standards clearly prefers heat pumps, which are far more efficient and cost effective. 

The government is only due to make a final policy decision on hydrogen for home heating in 2026. But the absence of viable trials and a growing chorus of opposition means few think the outcome is in doubt.  

Green hydrogen holds more promise for industry, but even here it does not look as though the gas grid will play much of a role. The part of the gas grid most suited to supplying hydrogen to industry is the high-pressure National Transmission System (NTS). This is the network that transports natural gas from production fields, import terminals and storage facilities to major consumption centres across the UK.


In a 2023 report for the National Infrastructure Commission (NIC), consultancy Arup looked at the National Grid ESO’s various Future Energy Scenarios (FES). All of these assume industrial demand for hydrogen begins in the early 2030s in clusters, before spreading further afield from 2035. 

Arup’s analysis concluded that the hydrogen and natural gas networks will need to be independent with no commingling. Both will also have to meet a 1 in 20 peak demand scenario, in addition to providing security of supply to customers. 

The problem, according to Arup, is that natural gas demand is not forecast to fall sufficiently by 2030 to allow the NTS to split into two systems. 

Instead, the UK’s initial hydrogen backbone would need to be a newly built asset. Arup does note that once major industry has transitioned to hydrogen in the mid 2030s, this will free up significant capacity on the natural gas system. The question is then whether that capacity is used to “transition customers onto hydrogen, or decommission areas of the network,” the report says. 

Green gas

When it comes to alternative molecules, hydrogen is not the gas grid’s only hope. There is a smaller group of advocates arguing in favour of biomethane. 

There are over 700 anaerobic digestion biogas plants in the UK, according to the government’s Future Policy Framework for Biomethane Production published in February. Over 100 are upgrading to produce biomethane for gas grid injection. 

In 2022, the UK produced and then injected into the gas grid 6.8 TWh of biomethane. The government expects its various support policies to increase this to 8 TWh by 2030. A separate Biomass Strategy published last year suggested that 30-40 TWh of biomethane production by 2050 would help achieve a “cost-effective” net zero based on the “best utilisation of feedstocks such as animal slurries, food waste and maize, sewage sludge and the upgrade of landfill gas”.

To put that 30-40 TWh in context, household demand for natural gas in 2022 was 254.4 TWh, down from 310.2 TWh in 2021. Total UK gas demand in 2022 was around 800 TWh. 

Some firms are already moving to take advantage of biomethane. In September 2023, AstraZeneca agreed a 15-year partnership with Future Biogas to establish the UK’s “first unsubsidised industrial-scale supply of biomethane gas”. 

An upgraded combined heat and power (CHP) facility fitted with bioenergy carbon capture and storage capability (BECCS) will generate 100 GWh of energy from biomethane annually – the equivalent heat demand of 8,000 homes.

The plan involves using locally-grown crops as feedstock. It will use regenerative agriculture practices that promote nutrient cycling and improve soil health, according to AstraZeneca. CO2 will be stored and sequestered at Norway’s Northern Lights project. It is a pleasingly circular system – but not one that seems likely to scale up. 

Scaling up

The government’s biomass strategy highlights that as biomass feedstock supply is so diverse, there is significant uncertainty when it comes to assessing future availability. 

“The problem is where do you get the feedstock from to make the bioenergy? There’s no answer to that,” said Richard Lowes, a senior associate at global NGO the Regulatory Assistance Project.

There are doubts about the future availability and cost – the UK imports around one-third of its biomass. But there is also a clear need to improve the sustainability and emissions standards around how biomass is procured and used. Biomethane’s high global warming potential means preventing leakage has to be a priority. An Imperial College London study from 2022 found biogas and biomethane supply chains leak up to twice as much methane as previously thought.

National Grid’s 2023 FES report says it is crucial to make sure biomass is used only for the most optimal applications. The various FES have total UK bioenergy demand in 2050 at between 150 TWh and 225 TWh. But in each scenario the great majority of the bioenergy goes to power generation followed by aviation – the volumes for industry and residential heat are tiny. 

“It’s just not a scalable market,” said Lowes. “The expectation, broadly, is that we’re going to be using less bioenergy in heating because it is needed more in other sectors.”

The life of an asset

If hydrogen and biomethane are not scalable substitutes, the question is then how much longer will the grid continue to carry natural gas. 

The answer is: longer than many climate activists would like to think. “Every man and his dog is modelling this question,” said one energy consultant who has worked with UK gas grid operators. “I’ve never seen anything that says we lose substantial parts of even the low pressure network by 2035.” 

Looking further ahead to the 2050 net zero deadline and things become very hard to predict. 

The reason for the gas grid’s likely longevity is that although customers are switching to heat pumps, they are doing so more or less at random. The government has put in place various subsidies for home decarbonisation, but ultimately opted to let the market run its course. 

Rolling out heat pumps in a co-ordinated fashion across a specific area would spell the end for a gas grid in a matter of years. A market-based approach means it would take a long time for heat pump density to start to cause problems for gas grid operations.

If left unaddressed, the problems would likely manifest in the form of cost. Ofgem regulates the prices gas operators can charge through the RIIO (Revenue = Incentives + Innovation + Outputs) framework. 

Death spiral

As more people leave the gas grid, the various charges that allow grid operators to recover capex and opex will fall on fewer customers. Bills will rise significantly. 

Source: Ofgem, RIIO-3 Sector Specific Methodology Consultation – Finance Annex

At some point, gas grid operators would submit cost requests to the regulator that would be so high relative to the number of customers they serve that it would be no longer compatible with a least-cost regulatory approach. 

This would likely happen first in networks operating in low-density rural areas. This is where the price of serving individual customers is already higher. On this metric, the first parts to fall would be the southwest of England, for example, or parts of Scotland. 

On the one hand, this is likely to be a long way off. Modelling for one UK grid operator suggests that gas demand will have to fall to 60% of its current levels before the impact on retail bills becomes intolerable for customers. 

On the other hand, it would be a terrible idea to let things get anywhere close to that stage. Higher charges would likely cause customers to defect from the gas network in greater numbers and at greater speed. This would risk creating what the energy industry terms a network “death spiral”. 

Unfunded liability

UK gas network regulation is based on a 45-year asset depreciation timeline. If assets become unusable within that 45-year timeline there is the lost value from a regulatory perspective. There is also the separate – and likely sizable – cost of decommissioning the asset. 

“It depends who you speak to but somewhere between £20bn and £80bn is the cost that we talk about to roll down the gas grid,” said Lowes. ”And that liability is totally unfunded.” 

Lowes highlighted that the 45-year timeline means UK citizens will still be paying for gas network assets installed today in 2068. As the current price-control period lasts until 2028, some assets will only be fully paid off in 2073. And this assumes zero capital investment beyond 2028. 

Regulatory shake-up

To Ofgem’s credit, it is clearly thinking about the issue. The RIIO 2 framework agreed in 2018 did not mention decommissioning at all. The consultation on RIIO 3, which closed just a few weeks ago, contains a ‘Future of Gas’ section. This highlighted the issue of how to pay for the potential decommissioning of assets if they are no longer required in the 2030s and 2040s.

Frank Hodgson, a senior energy analyst at Regen, welcomed the start of thinking about decommissioning. 

“Ofgem has clearly set out that current gas network charges are unsustainably low,” he said. “Electrification of heating is likely to be the best option for most households but in the long term we may need to protect those who are least able to electrify from paying unaffordable gas network charges.”

But there is sometimes a lack of clarity as to where responsibility lies in managing a shrinking gas network. “Key decisions on the future of the gas network are for Government to make,” an Ofgem spokesperson told E-FWD. It is the government that is in charge of the pace of change, how the transition to net zero will be paid for and by whom.

Giving direction to the gas grid

“You can imagine a future government might decide to set up something akin to the North Sea Transition Authority [NSTA] that has the responsibility to manage this in a co-ordinated manner,” said Hodgson. “It’s obvious that at some point the approach has to be more joined up.”

In a recent report for the Regulatory Assistance Project, Lowes laid out three potential solutions to the decommissioning issue. 

One is nationalisation and planned wind-down. Denmark took ownership of all gas distribution grids in 2021. It plans to switch all 400,000 connected homes to district heating or heat pumps by 2030. But the UK gas grid network is privately owned and connects over 20 million homes. The UK’s dire fiscal position and the politics of nationalisation make this option unlikely in the near-term.

A second option would be to continue with business as usual but accelerate depreciation. This is an option Ofgem has said it is considering. Higher charges would allow shareholders to recover costs by 2050. However, this would push up bills for all gas users and could risk a death spiral if bills increase rapidly. Charges would be even higher if Ofgem uses them to pre-fund decommissioning costs. 

Then there are the capital market implications to accelerating decommissioning. Gas network operators raise long term debt – typically 10-15 years but sometimes longer – in multiple currencies. They also enter into interest rate, currency and inflation derivatives to help manage risk. 

Derivative expense

Ofgem has suggested that operators would use some of the additional revenue from accelerated depreciation to make early debt repayments. But independent energy consultant Kathryn Porter said early debt repayment would also require buying back the derivative contracts.

“That’s obviously going to be expensive,” she noted. Accelerated depreciation and the risk of a death spiral could also mean grid operators struggle to issue longer-dated debt. “As they [operators] refinance debt, investors might start saying they are uncomfortable with post-2035 risk.” 

This would leave the various UK gas operators having to refinance debt at the same time, creating liquidity risk and potentially pushing operators towards the more expensive bank market. Ultimately, any higher financing costs would likely fall on consumers, Porter said. 

Similarly, if the regulatory asset value is depreciated to zero by 2050 but the UK still ends up being reliant on parts of the gas grid – the operators will not be able to use the capital markets for financing. The liability will fall on the government and taxpayers. 

Modelling 2050 is challenging. Heat pump roll out could well be slower than hoped. Offshore wind might continue to struggle with project costs. Net zero 2050 is obviously incompatible with substantial use of gas-based heating. However, regulators need to plan for the possibility that the UK misses its target. 

A third option outlined by Lowes is regulatory evolution, where gas operators evolve into clean heat providers. 

“They could become the parties responsible for delivering district heating in urban areas while simultaneously decommissioning the gas grids; their skills in pipework and roadworks could be well suited to such a challenge,” he said. 

But avoiding regulatory capture would require tight regulation. Lowes also noted this approach was not well suited to the UK’s “fully private and unbundled environment”. 

Scenario planning

Porter said a good starting point would be for Ofgem to engage with asset owners. They should discuss at what point low customer numbers would make the economics of operating infrastructure problematic. This would help the authorities plan in advance for certain scenarios and decision points. 

Essentially, what the regulator needs to establish, said Porter, are “principles for decommissioning”.

“The current [government] ambition is that by 2050 – absent the use of hydrogen – we’re not going to need the gas infrastructure anymore,” she said. “So what will be the plan for how we practically – in real life – go about decommissioning sections of the network.” 

There is much disagreement over the wisdom of Net Zero and the viability of electrifying almost all households. But there is solid consensus that what the industry and investors need is consistency and transparency. Unlike natural gas, these are still in short supply. 

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