Early in the 2010s the natural gas community adopted an “advocacy narrative”: that the carbon reduction benefits of coal to gas switching in power generation (and oil to gas in other sectors), and the advantages of gas in backing up intermittent renewables, would ensure that gas remains not just a transition — but also potentially a destination — fuel for a low carbon economy. This narrative was most prominent in Europe, but also advanced globally, mainly by international (oil and) gas producers and exporters. Although such arguments are highly persuasive from a short-term perspective, they do not address the priorities of national governments and the EU as a whole. This is because although they may result in early emission reductions, these will not be sufficient to meet 2050 COP21 commitments which are the increasing focus of government attention.

If gas is to maintain anything close to its current position in European energy balances gas post-2030, the gas community will need to move from its previous advocacy position to a “decarbonization narrative” which needs to include the following components:

The primary method of biogas production is the biological breakdown of organic material in the absence of oxygen known as anaerobic digestion. Biogas is principally used in local (mainly agricultural) networks to produce electricity, but it can be upgraded to biomethane by a variety of methods which can then be injected into pipeline networks and used interchangeably with natural gas. In 2017, biogas production in Europe was around 18 bcm but biomethane production was much smaller at 1.94 bcm (Bioenergy Europe, 2019, Table 2 and 4). A 2019 survey of renewable gases in Europe includes a database containing 497 operational biomethane projects most of which are located in Germany (46%), 20% in the UK and 7% in France and Switzerland (Lambert and Oluleye, 2019, Fig. 6b). Upgrading plants to achieve technical availability up to 96% results in an annual nominal potential for biomethane of 2.02 bcm/yr. Fig. 4 shows scenarios for biomethane production up to 2030 and 2050. The most optimistic of these sees the possibility of 98 bcm of biomethane from biomass sources by 2050.

Power to Gas (P2G) relies on the principle of electrolysis: using electricity to separate water into its component parts of hydrogen and oxygen. Scenarios of renewable hydrogen from surplus wind and solar power are around 50 bcm in 2050 with the majority of the increase post-2040. This suggests that unless a much larger surplus of low/zero cost renewable electricity becomes available, to significantly increase the scale of P2G dedicated off-grid renewable energy systems will need to be established in regions with high wind and solar resources with hydrogen being transported by pipeline to consumption centers.

In Europe, hydrogen is produced by the following fuels: gas 68%, oil 16%, coal 11% and electricity (electrolysis) 5% (DNV GL, 2018, Slide 12). Utilization of hydrogen from reformed methane is common in many parts of the world, but is mainly confined to the refinery sector and transported short distances to limited numbers of industrial customers. Large-scale methane reforming with carbon capture to produce hydrogen for network distribution to residential and commercial customers would be a completely new development.

Large-scale methane reforming to hydrogen with CCS is under serious consideration only in the UK and the Netherlands, while in southern Europe the initial emphasis has been more on biogas and biomethane development. The principal reason for this is the availability (or otherwise) of suitable offshore structures for carbon storage. Countries such as the UK and the Netherlands have offshore structures (depleted gas fields and aquifers) which are suitable for storing carbon dioxide. In central and southern Europe, lack of access to offshore storage structures means that the methane reforming option is logistically problematic and therefore less commercially viable. However, Italy and Spain are exploring the possibility of direct import of renewable-based hydrogen from North Africa through existing natural gas pipelines which would form part of a hydrogen “backbone” network (Wang et al., 2020).

The emphasis on offshore structures is the result of onshore carbon dioxide storage being considered politically impossible in major European gas markets due to environmental opposition. The rationale for such opposition is not entirely clear but has been accepted, which means that large capacity offshore structures — with pipelines leading to those structures — will be required. It also suggests that large-scale CCS must take place pre-combustion rather than post-combustion. There are clear logistical advantages to gas producers reforming methane and producing hydrogen either at the field or where the gas is landed onshore. The advantage of pre-combustion CCS would be that only offshore carbon dioxide pipelines would be needed. The potential disadvantage would be that all networks and customers in those regions would need to be converted to hydrogen, unless a further step was taken to methanize the hydrogen into syngas onshore (“power-to-methane” in Fig. 4) which would add to efficiency losses and therefore to costs (Fig. 5).

An alternative method of hydrogen production from natural gas is pyrolysis (or methane cracking) which splits methane into hydrogen and a solid carbon residue — carbon black — which can then be used in a range of industrial processes. Although the extent and scale of the utilization options for carbon black are uncertain, and large-scale storage would still be required, this could resolve some of the problems and costs of carbon dioxide capture and storage. The methane cracking process is currently at the laboratory testing stage and it remains to be seen how quickly it will develop. The next important step will be a small-scale plant to demonstrate the viability of the process.

An important conclusion from a review of the current progress of renewable and decarbonized gas options is that, to maintain anything close to the scale of the European gas market in the late 2010s, even the highest estimates of biogas, biomethane, and power to gas would need to be supplemented with the reforming of methane into hydrogen accompanied by carbon capture and storage. Fig. 4 is from ENTSOG’s Ten Year Network Development Plan (ENTSO-E and ENTSOG, 2019) and shows three new scenarios (right side of the figure) which are relatively consistent with those in Fig. 2 in terms of timing, but less ambitious in terms of volumes of power to methane and hydrogen.

It needs to be stressed that Figures 2 and 4 are presenting overall EU scenarios. They do not exclude — and indeed they specifically envisage — the possibility of individual countries, and particularly regions of countries, converting existing gas networks to a mixture of methane, biomethane, and hydrogen, or building new networks specifically to transport hydrogen. However, a 2019 database of renewable gas projects at different stages of development, from operation to planning, did not lead to an optimistic conclusion about the prospect of rapid development of commercial scale projects (Lambert and Oluleye, 2019).

In 2020, the EU published a three-stage Hydrogen Strategy which added some granularity to both the ambition and the funding of development. The first stage (2020–24) envisages 6 GW of electrolyser capacity, the second stage (2025–2030) capacity will expand to 40 GW and to 500 GW in the third stage (by 2050). In the first stage, hydrogen from local renewables or methane will be produced close to sites where it will be used. The second stage envisages retrofitting fossil-based hydrogen production with carbon capture which is when major new infrastructure development will be needed. For the period up to 2030, the Strategy envisages an investment of €24–42 bn in electrolyzers to which would need to be added: €220–340 bn to scale up and directly connect 80–120 GW of solar and wind capacity to the electrolyzers, €11bn for retrofitting half of the existing gas plants with CCS, and €65 bn for hydrogen transportation and storage infrastructure including refuelling stations (EC, 2020, pp. 7–8).

EU targets dictate that the power sector must be largely decarbonized by 2030, followed by the heat and transport sectors in the two subsequent decades. Consequently, the time available to demonstrate whether methane can be retained in the energy balance on a large scale beyond the next 20 years is relatively short. Following this logic, certainly by the mid-2020s — and arguably today — it will no longer be possible to sign contracts for methane exceeding 10 years (and even this duration may be difficult) unless it can be demonstrated that methane decarbonization arrangements will be in place by the end of that period. Similar logic suggests that it will not be possible to recover methane-related infrastructure investments requiring a longer depreciation period. Therefore, the necessity to demonstrate that the different decarbonized gas options are technically feasible and cost-effective against alternative low/zero carbon options is urgent, in order to provide sufficient time for a large-scale gas network transition over the following 25 years up to 2050, particularly if there is a need to convert significant numbers of customers to hydrogen. This means that the pilot projects currently in operation will need to be followed relatively quickly by commercial scale projects in order to be operational by 2025. This will require the technical, legal, regulatory, and fiscal frameworks to be in place to allow final investment decisions to be taken in the early 2020s.

It is extremely difficult to make accurate cost estimates for the different decarbonization options. Fig. 5 shows cost estimates for a wide range of renewable gas options in 2018 with projections for 2030 and 2050. Only the lower end of estimates for steam reforming with CCS come even remotely close to European hub prices which ranged from €5–21/MWh in 2019 and the first half of 2020. By 2030 costs of reforming and biomethane (anaerobic digestion and gasification) are projected in the range of €40–60/MWh, while the cost range for power to hydrogen is very much higher. But by 2050, costs of all these gases are projected in the range of €40–60/MWh. The EU Hydrogen Strategy has current costs of fossil-based hydrogen at €45/MWh, and renewable hydrogen at €75–165/MWh (Barnes and Yafimava, 2020). This means there is no current “business case” for investing in these projects, specifically no expectation that they will earn a commercial return, and this will need to be addressed through policy and regulation. The major policy instrument will be substantial additional carbon taxation, and fossil fuel exporters to the EU have been alerted to the fact that a carbon border tax is under active discussion in Brussels. The formulation and timing of such a tax, and the extent to which it would be compliant with WTO rules, are not at all clear but promise to be key issues over the next several years (Aylor et al., 2020).

As stated above, exporters of pipeline gas and LNG to Europe have good expectations of growth in the need for additional supply (despite the fact that demand may be flat or falling) over the next decade due to the likelihood that domestic production will fall faster than demand. However, anticipation that serious demand decline could start by the late 2020s and intensify significantly thereafter, raises questions regarding how long, beyond the mid-2030s, it will be possible to sell large volumes of unabated methane in major European gas markets. While the mid-2030s may seem a very long commercial time horizon, it is short in terms of the arrangements required for large-scale decarbonization of methane delivered through via pipelines or LNG projects. And it is certainly not a long time-horizon to ensure that networks and customers will be ready to receive decarbonized gas.

By the 2030s, most European domestic gas reserves — with the exception of Norway — will have been depleted. Therefore it is pipeline gas and LNG exporters, and those who own the networks which deliver their gas, which have the greatest interest in a methane-specific future post-2030. Large pipeline gas and LNG projects are designed to run for more than two decades, and developers of projects, particularly those which have yet to take a final investment decision (and therefore will not start operating until the second half of the 2020s), will need to consider the extent of European demand for unabated methane in the 2030s. The entire gas value chain will need to consider the possibility that national governments may specify targets — and potentially deadlines — for the phasing out of unabated methane (similar to the plans in many EU countries to phase out coal by the early/mid 2020s).

In the event of a reduction of opportunities for methane sales in Europe, pipeline exporters would need to decarbonize their product or accept that their pipelines will progressively become stranded assets. For Norway this may not be particularly serious. By the mid-2030s Norwegian gas production from resources in existing fields and discoveries may have fallen to around half the level of the late 2010s. While new discoveries are possible, there may be political pressure against their development for climate-related reasons and little commercial incentive given that the last major export pipeline for Norwegian gas to Europe was completed in the mid-2000s (Langeled) and the only subsequent pipeline (Polarled completed in 2018) is relatively small. Another relatively small pipeline (Balticpipe) is under development but the principal investors will be Polish and Danish companies.

By contrast, Russia’s Gazprom has a much larger resource base which could maintain exports at the level of the late 2010s for several decades. Several new large-scale pipelines have been built in the 2010s, and others are in the process of being completed. These pipelines will need to remain operational for 20 years to recover their capital costs. Gazprom’s much larger resource base and relatively recently developed pipeline delivery infrastructure means that it does not have the option (available to Norwegian exporters given their much smaller resource base) to run down its deliveries to Europe, possibly phasing out by 2050. For this reason, Gazprom must address the need to decarbonize its gas deliveries to Europe, starting in the 2030s, by converting natural gas to hydrogen.

In contrast to exporters with geographically fixed pipelines, LNG exporters faced with a requirement to decarbonize their product would have the option of exiting European markets and selling elsewhere in the world. But that possibility is likely to be unattractive for several reasons. European markets are significantly profitable with large creditworthy customer bases and many exporters have invested in LNG liquefaction terminals (and associated production and shipping) and have sales organizations which would be potentially stranded should they decide to give up their European gas business. Furthermore, it can be argued that in order to meet COP21 targets, many other parts of the world will have to consider decarbonizing methane post-2040, and it could be valuable for producers and exporters to gain experience in Europe. LNG exporters need to consider the potentially revolutionary options of reforming regasified methane into hydrogen either at the regasification terminal or at the wellhead and shipping hydrogen and/or ammonia rather than LNG. In both cases, the CO2 would be stored close to where it is produced in depleted fields. For those considering investments in new LNG projects whose principal market is (or could be) Europe post-2030, it is not too early to be considering these options. But all of these options will increase the costs of the delivered costs of the fuel which raises issues of competitiveness with other low/zero carbon energy options.

Logic suggests that the options for methane producers and exporters post-2030 are either reforming with CCS, or progressively exiting Europe. Outside the EU and most other OECD countries, the energy transition imperative is far less advanced in relation to decarbonization; improvement of air quality is much higher on government agendas and natural gas can make a major contribution here. The problem is affordability. Historically low real prices for LNG in 2019 and 2020 will provide a useful guide to import potential particularly in Asian markets.

One of the most difficult issues surrounding the compatibility of natural gas and LNG with greenhouse gas reduction is the measurement, in particular, of methane emissions from the gas value chain. A significant literature has evolved on the contribution of methane to greenhouse gas emissions, specifically “fugitive” methane from natural gas operations and (resulting from this) the extent to which coal to gas switching should be considered beneficial in terms of overall emissions.

Public domain literature uses generalized leakage factors for natural gas and LNG, usually from the US where most of the publicly available data and estimates originate. Much of the public literature on natural gas emissions — both methane and carbon dioxide — takes a figure, usually from a survey of several US sources extended to a national figure through modelling, and then generalizes the figure worldwide. High emission figures provoke protests from natural gas stakeholders who cite lower figures from other studies and corporate commitments and initiatives which have been undertaken — including OGCI, Methane Guiding Principles, Oil and Gas Methane Partnership, Collaboratory to Advance Methane Science (CAMS), Marcogaz/GIE and ONE Future — to reduce (particularly) methane leakage and promote carbon capture and storage (CCS).

Because high methane emissions threaten the claim of gases to be a beneficial energy transition pathway, certification will be the only way to achieve credibility of emissions’ estimates from the different elements of individual value chains. The emissions needing to be certified will be: