Re-envisioning the role of natural gas in a clean energy future

To meet climate goals, enormous changes to the world’s energy systems are required. The impacts will no doubt be significant for fossil fuels ranging from coal, to oil, to natural gas. With regard to natural gas, various regional and national pipeline systems represent important and large infrastructures with long life spans. Additionally, natural gas resources—proven, probable, and possible—represent an enormous asset. So, strategies that avoid stranded costs along the natural gas value chain while being aligned to climate objectives are attractive. “Clean” gas, or hydrogen sourced from natural gas, represents an alternative that has been receiving increased attention.

Within this wider climate framing, the United States is already promoting and expanding its natural gas exports substantially. Moreover, there is a sizable gas resource in the US that is not reaching market. Evidence of this is clear as significant volumes of natural gas are currently being flared in both the Permian and Bakken regions alone, with further growth projected. Flaring, while usually permitted to allow oil production in areas with insufficient natural gas take-away capacity, results in significant waste of otherwise useable energy resource. This wasted supply could provide a primary energy source in a hydrogen value chain based that provides economic benefit to producers and consumers.

Japan is developing hydrogen supply chains from Australia. This is a way to tap into remote energy resources, which include large scale solar and wind energy, for countries that lack indigenous supply. This is particularly true for large developing economies in Asia, many of which are becoming increasingly reliant on imported energy supplies. In producing regions, natural gas basins typically have geologic CO2storage potential, therefore conversion of natural gas to hydrogen close to production sites can be attractive. Hydrogen exports can offer an economically viable energy transition option for oil and gas producing countries that large developing countries would find attractive. As such, it could help ease tensions that may arise from the economic and geopolitical consequences of an energy transition.

If the process of converting natural gas into hydrogen is combined with CO2 capture and storage, the bulk of the associated emissions can be avoided. Still, worldwide just three plants for hydrogen production are employing CCS (Air products, Quest, and ACTL Sturgeon). One plant has dedicated storage while the others use the CO2for enhanced oil recovery, but quantities are modest, each at around 1 Mt per year.

But momentum is growing. In 2018, six new large-scale CCS facilities have been added to the Global CCS Institute database. All are in Europe – four in the UK and the republic of Ireland and two in the Netherlands – and all are related to decarbonised hydrogen production. One of them is the H21 North of England project. It will convert 3.7 million UK homes and businesses from natural gas to hydrogen. The feasibility study includes an extensive comparison of hydrogen from electrolysis vs. hydrogen from natural gas with CCS. The study concludes that the latter is 60-70% cheaper than the former (based on electricity prices of 40-70 pounds per MWh, and gas prices of 15-25 pounds per MWh). The idea is to produce ammonia from natural gas with CCS in Norway, then ship the ammonia to the UK where it is converted to hydrogen upon landing. The cost of such conversion roughly doubles the wholesale cost of gas. Some of that cost increase to consumers may be offset through higher efficiency at end-use, for example if fuel cells are applied for cogeneration. These figures indicate the potential viability of a hydrogen strategy based on fossil fuels (so-called “blue hydrogen”).

These “blue projects” must compete with “green” ones. The catalogue price for alkaline electrolyzers today is more than 1000 USD/kW. However, cost improvements could change the economics decisively in favor of renewable hydrogen supply (so-called “green hydrogen”). Cost improvements in renewable electricity supply have already changed the conversations about “green” hydrogen because very low cost renewable electricity at 2-3 US cents/kWh is critical for the economic viability of such pathways. Globally, costs for renewables are pushing this direction, and power purchase agreements (PPAs) in some parts of the world indicate that such levels can currently be reached, under the right conditions.

Because hydrogen is typically generated close to the point of primary energy production, the question of how to most efficiently transport it is open. While dedicated power plants with dedicated hydrogen supply may come online soon – for example in the Netherlands – hydrogen transport in existing natural gas infrastructure could be an important opportunity for a hydrogen fuel market.

One barrier to this part of the “hydrogen economy” is related to the need to refurbish transmission and distribution infrastructure, as well as the need to change standards and replace or upgrade certain equipment. Existing pipeline and equipment standards limit the amount of hydrogen that can be transported, typically to 10-20%. This offers the prospect of a significant hydrogen share. Recent analysis by the US Department of Energy indicates transmission pipelines can be used for hydrogen with limited adjustments to compressors and flanges. But, a gradual transition from a natural gas supply and distribution system to one that is entirely hydrogen-based may be unlikely. Such infrastructure shifts present economic and regulatory challenges that require close cooperation between public and private sector interests. So far only small-scale pilots at industrial facilities or residential districts have been contemplated and are being implemented in Europe.

One way to overcome the transport problem is to convert hydrogen into synthetic methane, particularly in the case of green hydrogen as such a step is certainly not economic with natural gas-sourced hydrogen. Today, the only synthetic methane that is injected into gas systems is produced from biogas. Germany and Sweden are leading in this space, but production of synthetic methane from hydrogen is currently only done at pilot scale. Car maker Audi has operated a system for synthetic methane from hydrogen with renewable power since 2013 that is sufficient to supply around 1500 cars, but cost data is not publicly available.

Agora Energiewende released a study in 2018 that concludes synthetic methane from renewable electricity will cost 200-300 USD/MWh. Further cost reductions could be expected with capacity investment, but the improvements must be significant to promote broad commercial adoption. To put this into perspective, natural gas for large consumers costs 30-35 USD/MWh today. So, the economics – current and future – are challenging. In addition, to address carbon emissions, large scale synthetic methane transport would require hydrogen conversion closer to end-use alongside a suitable carbon capture technology, but this may be possible at points of aggregation. In sum, potential cost hurdles associated with synthetic methane mean it will be critical to focus on applications where hydrogen use has a value added, for example where it can facilitate efficiency gains in the case of fuel cell applications.

Creating hydrogen or synthetic methane from renewables is technically feasible, but is a relatively costly proposition. In contrast, hydrogen from natural gas, while economically feasible, faces technical and regulatory challenges that may limit its roll-out for small-scale use. But, application at scale is critical. For industrial energy needs, dispatchable power, and perhaps for transportation, hydrogen from natural gas with CCS may be a viable option in parts of the world. The realization of such pathways will allow a significant portion of today’s energy infrastructure to play an important role in the evolution of global energy systems, which is critical to avoiding stranded costs and addressing the scale requirements of meeting future energy demands. This is especially important for many developing countries as they expand their natural gas infrastructure and contemplate future infrastructure investments.

Longer term, cost reductions for electrolyzers and the continually falling cost of renewable electricity will enhance the economics of hydrogen from renewable sources in the coming decades. This has potential to create a virtuous cycle for renewables-based electrical grids as hydrogen can provide much needed flexibility to power systems, acting as a buffer to non-dispatchable renewable generation. Certainly, hydrogen is attracting increased attention as a viable energy option – car-maker Toyota has made a significant investment with the roll-out of the Mirai and its strategic direction. But, accounting for the full suite of environmental and system balancing benefits can further strengthen the case for hydrogen solutions in the future energy system.