Oil and gas companies have been hitting the blogsphere to explain why gas has a future in a low carbon world. But if that is the case, why aren’t they investing much more in the new technologies that might make this possible?


 Natural gas has been promoted as a cleaner alternative to coal and oil. But it is still a high carbon emitter.



The climate emergency is beginning to have a direct impact on investment in fossil fuel based companies[1], their market valuation and even their attractiveness as a place to work. In response, the oil and gas companies[2] have been hitting the media and industry press recently with a series of articles and reports promoting the role that natural gas could play to help the global transition to low carbon energy.

There is a degree of “fossilsplaining”[3] going on here. Needing to explain to shareholders, employees, school children, governments and maybe also to themselves that fossil fuels still have a future, the more progressive oil companies have given up denying that climate change is happening and have instead begun to promote an evolutionary change. During this longer transitional period, natural gas has been promoted as a lower carbon alternative to the worst emissions coming from coal and oil.

It is easy to be cynical but there is some truth to this. The decarbonisation of the UK’s electricity supply[4], which has largely been presented as a story of renewable energy generation and changes in energy demand, has also been a story of gas displacing coal due to its lower marginal cost and carbon tax. As a heating fuel, natural gas is greener than oil, LPG or coal. For power generation, efficient gas fired CCGT[5] power stations have significantly lower carbon and particulate emissions than coal.

High-Res Coal Generation Over Time - GB electricity demand

Figure 2 The demise of coal – will natural gas go the same way?

Natural gas is a high carbon fuel.

On the basis that gas will supersede coal, some analysts have even described this period as a “golden age”[6] for gas. But whatever we say about it’s relative benefits, there is no getting away from the fact that natural gas is still a high carbon fuel. Unless natural gas usage can be decarbonised this must be a very short golden age, measured in years and not decades, if we are to meet the climate emergency challenge.


This is an uncomfortable truth for the natural gas industry. In any credible net zero carbon scenario, burning unabated[9] natural gas to generate power or heat is simply not going to be an option. Put simply, having a natural gas boiler to heat homes is not compatible with a net zero carbon outcome. That means that nearly all of us are going to have to change our household heating system.

Natural gas may have a transitional role in those countries still dependent on coal, but very soon burning unabated gas will no longer be compatible with efforts to combat climate change. For developed economies like the UK, US and most of Europe that point has already been reached, the shift away from coal should now be immediately followed by a shift away from natural gas.

Hybrid technologies that use natural gas as a backup fuel, such as hybrid heat pumps[10] or heat networks using combined heat and power (CHP) plants, may have a longer transitional role. However, these technologies must also be phased out in net zero carbon world, unless they can convert to a low carbon fuel such as hydrogen or biomethane.

There may conceivably be some uses for unabated gas in exceptional circumstances, maybe some industrial process, if no other fuel is viable. But looking out over the next 30 years of technology development and energy innovation, it is difficult to think of an example where this would necessarily be the case.

Vital but diminishing role

How can this assessment of the need to stop using natural gas be reconciled with the widely held view that natural gas still has a ‘vital role’[11] to play as a transitional fuel, keeping the lights on and complementing the growth of renewable energy? Proponents of the ‘vital role’ are correct; in the near term at least, gas still has an important role to play, displacing coal in some economies and providing much needed flexibility to balance energy systems with higher levels of renewable energy. However, it is entirely consistent to say that gas will continue to play a vital role while at the same time saying that the overall demand and usage of natural gas must diminish rapidly.

In the UK, and other countries with higher levels of renewable energy, the use of gas for power generation has already begun to transition from providing base load towards meeting ‘peak’ demand periods and balancing energy supply. This is largely being driven by the ‘merit order’ effect which means that generation technologies with higher marginal costs (the cost of gas and associated carbon tax) are eased out of the market by lower marginal cost wind and solar.

Regen’s analysis suggests that under full decarbonisation scenarios UK demand for natural gas, as an end use fuel[12], will peak in the mid 2020s and fall rapidly in the 2030s and 2040s.  National Grid’s Future Energy Scenarios paint a very similar picture.

Getting natural gas out of the heat supply market is a much more difficult proposition. Over 80% of UK households are still reliant on cheap[13] natural gas as their primary heating source, this will require radical decarbonisation actions and a shift to new technologies[14] which will take time. So far, little progress has been made. The government’s signal that no new homes should be gas connected by the mid-2020s is positive but that’s not going to deliver the minimum 40% reduction in domestic heat carbon emissions which will be needed by 2030 to be on track for the UK’s 5th carbon budget.

Challenges abound but the key point is that, if we are to achieve net zero carbon, then one way or another we need to stop burning unabated natural gas.

Is there a long term future for natural gas in a net zero world?

The broad answer is “yes there could be”, but the future of natural gas in a net zero world is reliant on the development of new technologies that would enable natural gas usage without the associated carbon emissions. There are several potential technologies that could achieve this, but the main opportunities lie with:

  1. Carbon capture (usage) and storage (CCS or CCUS),
  2. Natural gas to hydrogen conversion, known as “Blue hydrogen”, which also relies heavily on CCS.

1) Carbon Capture and Storage

The idea behind CCS is to capture CO2 at the point at which natural gas energy is converted – in a power station, hydrogen production plant or possibly within industrial plant applications. CCS technology has been used and deployed at small scale, but the large scale adoption of CCS has been delayed, with the usual issues around stop-start governmental support, and still faces several challenges. The UK’s Committee on Climate Change(CCC) has identified that “CCS is essential”[15] across a range of applications, other analysts have however cautioned that, mainly because of its associated cost, CCS cannot be seen as a silver bullet.

The widespread deployment of CCS faces a number of challenges. First there is the capital and operating cost of CCS technology, and the efficiency of the CCS process which today typically captures only circa 40-60%[16] of carbon emissions. Under the CCC’s “Further Ambition” net zero scenario CCS capture rates must improve to 95%. That’s a huge improvement in the underlying performance. CCS also brings a potential loss in efficiency in the energy conversion process it is supporting, reducing the output of power, heat or hydrogen produced if CCS is used.

Then there are the logistical costs of carbon transport and storage (sequestration). In a nutshell we would have to potentially manage millions of tonnes of carbon and put it somewhere where it won’t just leak back into the atmosphere.

Some innovative uses of carbon have been identified which could provide value to offset these costs, pumping carbon into oil and gas wells to enhance oil recovery (EOR) rates for example. A serious potential flaw in the EOR usage case is that a significant proportion of the carbon pumped into oil and gas wells can escape back into the atmosphere[17]. Another potential option would be to create solid carbon (carbon black) which can then be used in the manufacture of tyres, rubber, plastics and printers.[18]

Given these challenges it is understandable that the fossil fuel based industries have been reluctant to throw investment into CCS without a high degree of government support. There is also an inherent dilemma facing the industry whether to embrace a new technology, which will raise their cost base, and will help to hasten the demise of the legacy assets which they are trying to sweat.  There could be a case of first mover disadvantage. Most analysts have, therefore, highlighted the need for governments to offer encouragement and incentives in the form of grant funding and subsidies in order to get the CCS technology moving.

Turning back to the discussion about how CCS might impact the future role of natural gas for electricity generation we could envisage three possible outcomes:

Jg 4a

2) The future of natural gas as a feedstock for hydrogen

If CCS is an enabler to extend the life of natural gas, then conversion to hydrogen offers the potential for a long term future.

There is no question that low carbon hydrogen will be an important fuel in the future. It has already been identified as a potential fuel for areas of the economy that may be difficult to decarbonise; industrial processes, some forms of road transport, marine transport and potentially aviation.

The future of hydrogen raises two big questions which will determine whether the use of hydrogen creates a long term market for natural gas:

  • Will hydrogen become a ubiquitous fuel used to meet mass energy requirements for heat and transport, or will it be limited to high value applications in transport and industrial processes? To become a ubiquitous fuel, it needs to be cheap, much cheaper that the current production processes would allow.
  • How will low carbon hydrogen be manufactured? Using natural gas, electricity or some other process? If electrolysis dominates, using low cost renewable electricity, then the outlook for natural gas is much less attractive.

Hydrogen manufacturing

Hydrogen is considered a low carbon[19] fuel because at the point of use (combustion or chemical conversion via fuel cells) the only emission is water. Hydrogen differs from natural gas in several other respects:

  • hydrogen has a lower volumetric energy density, it therefore requires more volume, flow or higher pressure to deliver the same energy content
  • it has smaller molecules and therefore a greater propensity to leak and disperse
  • it is more buoyant and therefore has a propensity to rise within a storage vessel or in the atmosphere
  • it has different combustion properties and is more flammable; safe usage would require modification to most appliances
  • it corrodes metals and is therefore not suitable for older iron pipework used in our gas networks

A key advantage of hydrogen is that it can be manufactured in numerous ways[20], for example from coal and oil, and from new processes that are still in development. To consider its potential to create a future market for natural gas we will focus on two main manufacturing processes:

  • Hydrogen produced from natural gas using a form of steam methane reformation (SMR) and Known as “blue hydrogen”.
  • Hydrogen produced via electrolysis, using water and electricity. Known as “green hydrogen” on the assumption that it will use low carbon renewable electricity as times of excess supply and therefore low cost.

A first point to make is that hydrogen produced using SMR MUST be combined with CCS for it to be considered low carbon. Hydrogen SMR without CCS would entail even higher carbon emissions[21] than natural gas. This is inherent to the SMR process since there is a conversion inefficiency between methane and hydrogen energy.

With today’s SMR technology it takes the equivalent to 1.3 to 1.4 kWh of natural gas methane energy to produce 1 kWh equivalent of hydrogen energy[22]. This means there is a very significant energy conversion loss, and a higher carbon emission, to convert methane to hydrogen energy. Adding CCS to the process, using existing technology, implies additional cost and a reduced conversion efficiency.

Green hydrogen manufacture via electrolysis also entails a conversion energy loss. Using current processes, it requires around 1.4 kWh of electrical energy to produce 1 kWh equivalent of hydrogen[23]. Hydrogen produced via electrolysis is, however, of higher quality (fewer impurities) suitable for transport uses.

So, both electrolysis and SMR manufacturing processes have significant fuel conversion efficiency challenges. Innovation and further technology development can be expected to improve this over time, but for the moment hydrogen use will be restricted to high value applications.

In addition to the input fuel or power, the manufacture of hydrogen for mass energy use faces several additional cost challenges, including the:

  • Capital and operating cost of hydrogen conversion plant via SMR+CCS or Electrolysis
  • Cost and inefficiency of adding CCS, including the logistical costs of long term carbon storage (sequestration)
  • Changes required to gas networks, vehicles, industrial processes and appliances
  • Additional cost of hydrogen purification which will vary by manufacturing process and depending on the hydrogen usage. Fuel cells for transport require very high quality hydrogen.
  • The need for daily and seasonal hydrogen storage

This last point is significant. Storage has largely been removed from the natural gas supply chain in the UK[24] as we have moved to a “just in time” delivery relying on daily storage within the gas network (linepack storage) and continuous supplies landed from the North Sea and continental pipelines. It is inconceivable that the UK would build sufficient manufacturing capacity to supply hydrogen in a similar “just in time” manner to meet peak demand. The implication therefore is the need to build storage facilities for hydrogen on a daily and a seasonal basis. Noting that given hydrogen’s lower energy density, compared to natural gas, more storage will be required for an equivalent energy yield.

Electrolysis versus SMR+CCS

There isn’t a clear answer as to whether electrolysis or SMR+CCS will become the dominant hydrogen manufacturing technology. They could also co-exist, each providing hydrogen for different markets and supply chains. It is also possible that distinct regional supply chains will develop.

Electrolysis would tend towards a more distributed supply chain architecture, providing high quality hydrogen suitable for transportation and industrial process, and potentially for distributed hydrogen heat networks.  Electrolysis could also take advantage of regular low cost renewable electricity during times of over supply which would help to address some of the cost issues described above.

SMR plus CCS could lend itself to very large scale manufacturing and distribution, exploiting falling world natural gas prices and linked to the energy infrastructure for natural gas in the North Sea both for gas supplies and carbon sequestration.

The technical, logistical and cost challenges facing hydrogen are significant. But perhaps the biggest investment risk facing both forms of hydrogen manufacture is the en masse conversion of consumers and markets from their existing fuels.

Different development pathways could be taken including:

  • Industrial and transport hydrogen clusters combining hydrogen manufacture and industrial consumers linked by a local hydrogen network[25]
  • Hydrogen fuelled heat networks – larger hydrogen boilers potentially with on-site hydrogen manufacturing linked to domestic and/or commercial heat networks
  • Large scale hydrogen gas networks – conversion of whole cities probably on a borough by borough basis to hydrogen[26]
  • Hydrogen blending into existing gas networks – up to a limited concentration of circa 10% energy content (or 20% volume) which would create an important steppingstone to allow the growth of hydrogen manufacturing capacity. See for example the HyDeploy project at Keele university.[27]

In terms of viable pathways, electrolysis perhaps has an advantage over natural gas SMR. Electrolysis could grow incrementally from relatively small high value hydrogen applications. To be efficient SMR requires scale, it also requires significant investment in CCS infrastructure and logistics. To get to that scale would require a leap of faith on the part of investors and consumers to make the switch to a new fuel source. There is also the ongoing cost and energy security risk associated with natural gas imports.

Where are the oil and gas companies?

Given the size of the prize, and the opportunity to secure a long term future for natural gas, you would assume that the big oil and gas companies would be all over CCS and Hydrogen in terms of leading innovation and investment.

However, that doesn’t seem to be the case. For an industry that prides itself in breaking new frontiers and its can-do style of management, it is odd that the oil and gas majors are not ploughing millions, or indeed billions, into hydrogen manufacture from gas and supporting CCS technology.

Without doing a full analysis it is hard to tell how much the oil majors are investing in this area but a quick look at what BP and Shell are investing in begins to tell a story.

Shell’s future energy website shows that they are clearly thinking about the future of hydrogen[28] and exploring this from all angles. The focus of investment however seems to be aimed at creating hydrogen filling station networks for transport with very little obvious direct investment in blue hydrogen manufacturing or CCS. Shell UK is part of a consortia looking at the feasibility of deploying CCS at a new gas power station on Teesside.

If anything, Shell’s decarbonisation investment focus is shifting more towards electricity production, batteries and, in particular, electric vehicles.

BP can point to a number of hydrogen manufacturing investments in the pipeline. For example, the Rotterdam Hydrogen Quest, and a joint venture with Uniper to develop a hydrogen manufacturing plant at Lingen in Germany. A closer look however shows that both these initiatives are based on green hydrogen production via electrolysis, not natural gas conversion.

So here is the paradox, while Shell and BP are keen to publish blogs and articles which present a long term role for natural gas in a decarbonised world, when it comes to actual investment in the technologies that might make this possible, the oil companies seem reluctant to put their hands in their pockets.

Meanwhile, as well as continuing to invest billions in old style fossil fuels, where oil companies are investing in new low carbon technologies their focus has been to diversify into renewables, electric vehicles and electricity supply. Where hydrogen does feature in BP’s and Shell’s innovation strategy it is via electrolysis not natural gas conversion, with eyes very much on the use of hydrogen for transportation and industrial processes, not as a substitute for natural gas in heating and power generation.

The oil industries strategy may change. Maybe they are waiting for stronger government support to de-risk investment. Another more obvious theory is that it is very hard for a fossil fuel company to make a radical change in its business model, especially one which might cannibalise its existing profitable assets. Shell[29], for example, missed out on the first round of offshore wind when it could have become a world leader and instead left the field clear for Dong (now Orsted).

It is positive that Shell and BP want to diversify their energy portfolio, but it is still surprising that, while continuing to argue that natural gas has a low carbon future, the oil majors seem unwilling to commit the investment and innovation needed to make this happen.


Johnny Gowdy is a director at Regen. His near-30 years of experience working in the energy sector has taken him from the oil and gas to renewable energy.

Regen is a not for profit centre of energy expertise and market insight whose mission is to transform the world’s energy systems for a low carbon future.

Regen is currently developing a new thought leadership paper on the future of heat and decarbonisation. It will be published in spring 2020.


[1] For example https://www.theguardian.com/environment/2019/nov/15/european-investment-bank-to-phase-out-fossil-fuels-financing

[2] Bob Dudley “Gas in a Net Zero System” October 2019  https://www.bp.com/en/global/corporate/news-and-insights/speeches/gas-in-a-net-zero-energy-system.html

[3] See, for example Bob Dudley, or Shell CEO Ben van Beurden, CEO https://www.shell.com/media/speeches-and-articles/2019/embracing-evolution.html

[4] Which has now fallen from over 460 gCO2e/kWh to under 250 gCO2e/kWh since 2012. See BEIS carbon emission conversion factors https://www.gov.uk/government/publications/greenhouse-gas-reporting-conversion-factors-2019

[5] CCGT = Combined Cycle Gas Turbine, OCGT = Open Cycle Gas Turbine, which is cheaper but less efficient.

[6] See for Example Dieter Helm “Burn out : the End Game for Fossil Fuels” see also our review https://www.regen.co.uk/book-review-of-burn-out-the-endgame-for-fossil-fuels-by-dieter-helm/

[7] SEE BEIS published carbon emissions conversion factors https://www.gov.uk/government/publications/greenhouse-gas-reporting-conversion-factors-2019

[8] Based on a power requirement of 3.5 MWh and a heat requirement of 10 MWh.

[9] Burning gas without some form of carbon capture and storage

[10] Modelling suggests that a well-designed hybrid heat pump system may rely on gas for 20-30% of the heat delivered. Against a previous 80% carbon reduction target this could, it is argued, be a transitional technology. The net zero target we need to achieve removes this argument except in the very short term.

[11] See for example BP https://www.bp.com/energytransition/

[12] Not including its use as a potential feedstock for hydrogen manufacture discussed below

[13] The domestic energy market in the UK is significantly distorted in that levies for renewables and most energy efficiency measures, and carbon taxes, are added to the cost of electricity and not to domestic gas.

[14] Regen is currently writing a new paper on heat decarbonisation which will be published shortly.

[15] CCC https://www.theccc.org.uk/wp-content/uploads/2019/05/Net-Zero-The-UKs-contribution-to-stopping-global-warming.pdf

[16] Some trail CCS projects have achieved even lower rates, especially when retrofitted to existing fossil fuel plants – but this is an area of technology development.

[17] “Retention rates during EOR production ranging from as high as 96% to as low as 28%, largely depending on the formation type” (Olea, R.A., 2015. CO2 retention values in enhanced oil recovery. J. Pet. Sci. Eng. 129, 23–28. https://doi.org/10.1016/j.petrol.2015.03.012).cited by IRENA “Hydrogen : A renewable energy perspective”

[18] See IEA report “The future of hydrogen: Seizing todays opportunities” 2019 page 42

[19] There is ongoing research about the indirect greenhouse effect of hydrogen if it is allowed to leak into the atmosphere see https://www.geos.ed.ac.uk/~dstevens/Presentations/Papers/derwent_ijhr06.pdf

[20] Around 120 million tonnes of hydrogen are produced today mainly for industrial purposes. 95% is produced from coal, oil and gas and the rest via electrolysis.

[21] Hydrogen from steam methane reforming (SMR) without CCS has an emission factor of around 285 grams of CO₂ per kilowatt-hour (kWh) higher than natural gas

[22] ETSAP https://iea-etsap.org/E-TechDS/PDF/P12_H2_Feb2014_FINAL%203_CRES-2a-GS%20Mz%20GSOK.pdf

[23] Irena Hydrogen From Renewable Power https://www.irena.org/-/media/Files/IRENA/Agency/Publication/2018/Sep/IRENA_Hydrogen_from_renewable_power_2018.pdf

[24] UK currently has potential storage capacity of LNG and natural gas equivalent to approximately 12 days of average demand https://www.theyworkforyou.com/wrans/?id=2019-02-11.HL13575.h&p=13493

[25] For example see North West and North Wales clusters https://hynet.co.uk/ and South Wales http://www.h2wales.org.uk/

[26] See for example Leeds H21 project https://www.h21.green/

[27] HyDeploy Keele University with Cadent https://www.keele.ac.uk/discover/news/2019/september/hydrogentrialatkeelecoulddramaticallycutukscarbonemissions/hydeploy-trial-keele.php


[29] Shell was an early partner in the London Array but withdrew in 2008 – just in time to miss the massive growth of offshore wind in Europe. Dong (now Orsted) stayed in.  http://news.bbc.co.uk/1/hi/business/7377164.stm

Stay informed

Sign up to the Regen newsletter to receive a monthly digest of our work to revolutionise the UK energy system, and industry insights.

We take care of your personal data. We will only contact you according to your preferences and will NEVER share or sell your details. See our privacy policy for more information