CCS and blue hydrogen – how are regulators and markets positioning themselves?

Author Andrea Valentini, principal consultant

CCUS (Carbon Capture, Utilisation, and Storage) is receiving significant attention as corporations scramble to find cost-effective measures to meet net zero targets. What are the potential challenges for blue hydrogen from a regulatory and market point of view?

CCS and blue hydrogen – production pathways and potential regulatory challenges

The use of CCS as a tool to reduce GHG emissions from polluting industrial processed is receiving substantial interest from markets and regulators. There is significant interest in using CCS technology to produce low-carbon blue hydrogen as a relatively cost-effective stepping stone on the path to net zero, while in the short term green hydrogen production is likely to suffer from high production costs as electrolyser technology matures.

There are several potential CCS/carbon capture utilisation and storage (CCUS) pathways available for hydrogen producers. A potential issue that project developers might face is that not all options are likely to be treated equally because of possible stringent regulations and certifications linked to the lifecycle emissions of blue hydrogen and its derivatives. We highlight the main issues below:

Carbon capture stage:

  • If we look at ammonia as one of the main uses of hydrogen currently, a key advantage of deploying CCS solutions to ammonia production is that process CO2 in steam methane reforming (SMR)-based ammonia production is quite easy and inexpensive to capture. This typically represents 50-70% of an ammonia plant’s CO2 emissions. Several companies already capture this CO2 and sell it to third parties, currently for enhanced oil recovery in the US, or for other industrial processes

  • But flue gas CO2 would be much harder and expensive to capture because of a much lower CO2 concentration. It is typically released in the atmosphere

  • We would assume that “true” CCS-based blue ammonia production will have to be based on >90% of carbon capture. Using autothermal reforming (ATR) instead of SMR would partly solve this issue. ATR, despite being traditionally considered a higher-cost solution compared with SMR, would allow for the recovery of a much higher percentage of process CO2 (around 90%) compared with SMR


Carbon storage stage:

  • Enhanced oil recovery (EOR), despite being a readily available and cost-competitive storage option might be problematic because captured CO2 would allow the production of additional CO2 from oil that otherwise would have not been extracted. Of course, a more pragmatic way of looking at this issue is that EOR would still allow for carbon capture for producing a barrel of oil that would have otherwise been extracted elsewhere without CCS. If the more intransigent view prevails, according to the IEA between 300kg of CO2 and 600kg of CO2 is injected in EOR processes per barrel of oil extracted, although this varies greatly depending on the type of field and stage of development. Given that a barrel of oil releases around 400kg of CO2 when combusted, and around 100kg of CO2 on average during production, processing and transportation, this means that the environmental benefit of using EOR as a carbon storage solution could be questionable

  • It is also arguable that lifecycle emissions, including upstream methane leakage, will have to be taken into consideration. At a regulatory level EOR will come under scrutiny and in the longer term might receive lower incentives. Note that this is already a mechanism that is recognised for instance by the US government in its 45Q scheme:

  • — Companies such as ammonia producers that sell or use their CO2 for CCUS practices receive a tax credit that depends on the type of CO2 storage used. CO2 stored in saline aquifers receive $50 per tonne of CO2 stored, while utilisation in products, including EOR, receive only $35 per tonne of CO2

  • Using downstream chemicals as carbon sinks might also be problematic because some of the options taken into consideration do not guarantee the permanent storage of CO2 along the entire supply and value chain. Producing products like methanol with captured CO2 might be risky because methanol has significant fuel-related applications and might be burned in the destination market. Claims of carbon “usage” in downstream products such as urea are even more outlandish given that carbon in urea will be fully released after it is applied and absorbed by the soil. Chemicals and plastics as carbon sinks might require a very complex level of certification and verification

  • Storage in deep saline aquifers and depleted oil and gas fields are therefore potentially a safer option from a regulatory point of view. But this could limit the geographical scope of blue hydrogen and impact costs depending on the location

    Fig 1. Blue hydrogen pathways and potential regulatory challenges

    Fig 1. Blue hydrogen pathways and potential regulatory challengesClick chart to view full size

    Market acceptance — are clear market divides shaping up for green versus blue hydrogen?

    There are signs of a market split between countries that are clearly incentivising blue hydrogen production, and also actively investing in projects, and other locations in which regulators and consumers are taking a more cautious approach. The different approached of the EU and Japan are a good example of this, with the latter being involved in the potential supply chain of blue hydrogen carriers such as ammonia, while Europe is apparently favouring the renewable hydrogen route.

    The EU’s Carbon Border Adjustment Mechanism, and therefore its Emissions Trading System, is supposed to have provisions for blue hydrogen, as it is recognised as a needed interim solution to reach the block’s hydrogen ambitions. The new Renewable Energy Directive rules would require 50% of hydrogen consumption in Europe, including for instance SMR feed to ammonia synthesis, to be renewable at member state level. This seems to clearly favour green hydrogen production and consumption in Europe.

    But Japanese potential importers appear to have a more neutral and cost-driven approach. Several major Japanese corporations are involved in potentially producing and buying blue hydrogen and derivatives. Most of the recent project activity in the US also seems to be geared towards CCS, which clearly features in the US government’s decarbonisation plans and might receive future substantial incentives. The US Congress is due to discuss an increase of the 45Q tax credit given to CCS projects from the aforementioned $50/t CO2 to $85/t.

    Fig 2. Are clear market divides shaping up for green versus blue hydrogen?

    F ig 2. Are clear market divides shaping up for green versus blue hydrogen?Click map to view full size

    Argus’ consulting team is well placed to research and advise on carbon emissions, hydrogen and energy transition related:

    • Feasibility studies
    • Project valuation
    • Due diligence
    • Strategic planning
    • Policy and regulatory analysis
    • Market entry studies
    • Market supply strategy
    • Price and fundamentals forecast

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