Key success factors for US clean ammonia to reach FID

Clean ammonia, whether blue ammonia produced with the use of carbon capture or green ammonia produced with the use of electrolytic hydrogen, has been heralded as a medium to help decarbonize various industries. Potential use cases range from substituting conventional ammonia with low-carbon ammonia in the fertilizer industry – which constitutes some 80% of the ammonia market today – to alternative applications like maritime transport and power generation fuel blending. Ammonia can be suitable as an energy carrier and as a storage medium given its energy density and pressurization properties. This status has led some market participants to view the ammonia export market as a major potential growth area. Indeed, of the 30+ million tons per annum (MTPA) of announced large-scale US clean ammonia capacity (see Figure 1), the majority is concentrated in the US Gulf Coast, highlighting the potential waterborne export opportunity and the current geographic concentration of conventional production (see Figure 2).

The US is the third largest ammonia producer globally (see Figure 3). Given domestic conventional ammonia production of some 17 MTPA, the announced clean ammonia projects would represent a near tripling of current domestic production capacity and one-third of global demand. If realized, this buildout would substantially shift the dynamics of the market. Waterborne exports currently stand only at some 18-20 MTPA, as most ammonia consumption occurs within an integrated facility for derivative production. Expansion at this scale is likely to be difficult in the short term, given the lack of a developed differentiated product market for clean versus conventional ammonia in established sectors and limited commercialized adoption of ammonia in alternative uses.

Final investment decisions (FIDs) for clean ammonia have been slower to materialize than announcements. That gap is expected for large-scale capital-intensive projects. But the momentum may be lagging, as potential market participants seek to understand how robust a premium-priced differentiated market will be in terms of volume and price, how alternative uses for clean ammonia will develop against incumbent fuels or other alternatives, how to benefit from the myriad available incentives and regulations globally, what carbon intensity customers will demand – and how this will impact required infrastructure and thus project cost.

Such projects are sizeable expenditures for project partners/developers, but they also represent potentially significant investments and switching costs for end users, especially for alternative ammonia uses. These investments may include infrastructure to “crack” ammonia back into hydrogen and retrofits to allow for fuel blending at a power plant. If ammonia is used as a storage carrier, the conversion loss at the point of end use to crack ammonia back to hydrogen is nearly 30%. In sum, there must be a significant degree of clean ammonia buy-in from both producers and consumers, given the up-front investment that may be necessary to enable use.

Projects that move to FID are likely to be well-positioned for securing binding offtake. That may include access to existing infrastructure that shortens speed to market and helps pare down initial capital outlay. Location matters to realize shipping efficiencies. Project partners with experience at various phases of the clean ammonia value chain not only bring expertise, but can share in the capital commitment and risks.

This research note will focus on large-scale blue ammonia project development in the US and the potential export market for those products. We note that global announced clean ammonia capacity is also sizeable and hopes to satisfy many of the same export market segments. Supply sourced from the US may have some key advantages for the export market vis-à-vis other regions. The US has a well-established system of property rights and corporate law. For waterborne exports, in particular, historical disruption of products leaving the US generally have been linked to weather events like hurricanes and fog, and are typically short in duration. For exports that would be destined for European markets, the extent to which the European Union’s Carbon Border Adjustment Mechanism (CBAM) may allow lower-cost imports to remain competitive in the market before the mechanism fully ramps could also leave the US relatively advantaged, as we detailed earlier this year. The US is likely to remain globally competitive due to its sizeable natural gas production base, which tends to be strongly discounted versus other global price benchmarks. Additionally, natural gas supply curtailments or interruptions tend to be minor in the US and are typically tied to weather, like freeze-offs at the natural gas wellhead. There also has been no historic precedent at the federal level to hold back exports to satisfy the domestic market.

Current US operational clean ammonia capacity is small compared to conventional capacity. A 20MW electrolyzer that can produce up to 20,000 tons of green ammonia annually reached mechanical completion this April at the CF Industries Donaldsonville Complex. Some microscale green ammonia is slated to come online before the end of the year. A number of blue ammonia projects are moving forward.

Blue ammonia must have proximity to pipelines to feed energy to the project, and hydrogen and nitrogen for feedstock in addition to the proper takeaway and sequestration for carbon dioxide. Waterborne access is critical to clean ammonia, as well as numerous other large-scale export-oriented projects for LNG, NGLs, crude oil, and renewable fuels that exist across the project maturity spectrum. In some cases, facilities undertaking substantial infrastructure construction require nearby laydown space to enable those activities. Once in operation, they will require dedicated space for storage to accommodate day-to-day function and seasonality, but in some cases to also take advantage of time spreads.

As such, access to appropriate landholding will be pivotal to project success across various energy types. Key attributes that make a particular landholding attractive include whether it is close to project partners, large enough to accommodate the project and its growth ambition, optimal port location in terms of depth and width to accommodate the size of vessels that will engage in trade, the degree of pilot traffic restrictions to optimize shipping, and nearby existing infrastructure that can be leveraged for production amongst other factors.

Given recent consolidation across the US energy complex and the inroads that some established/traditional energy companies hope to make in the low-carbon energy space, some industry participants may be looking at landholding as the key to export optionality. That optionality gives them the opportunity to decide what potential projects in their portfolio are attractive for FID. It also enables them to realize operational efficiencies with their other assets, potentially allowing for asset upsizing or conversion, and ultimately optimization across their portfolio.

Notably, the land needs for the full project value chain may extend beyond the footprint of the ammonia facility itself. In some cases, this may involve securing the land (and related pore space rights) for carbon sequestration wells. These wells could be part of a dedicated sequestration for clean ammonia site or part of a site that provides sequestration as a service, given the various emissions-intensive industries concentrated in the region.

Given all of the above, recent transactions for pore space leases and dock and land purchases are not unsurprising across the wider energy complex perspective, not just for clean ammonia.

Tied into the value of land consideration is the value of existing infrastructure. If that land will indeed be developed for use in the carbon management/ammonia value chain, some projects may be better positioned for FID if they have access to existing project components. This could include access to refrigerated large tank storage capacity, direct access to pipeline, or appropriate docking facilities in terms of size and configuration.

The clean ammonia production chain is complex (see Figure 3), and various firms may have existing competencies in specific functions within a project. As such, a partnership approach may be beneficial, considering the project scale, costs, and risk. Of the announced projects, there appears to be no one-size-fits-all approach to forming these partnerships.

Outside of the supply or technology side of the value chain, offtakers that seriously envision a sustained end use for clean hydrogen may also view equity interest in a project as optimal rather than a tolling agreement. This allows the equity-owning offtaker more control over their volumes and pricing, as well as profit sharing in project success. In some cases, an ownership stake may also be preferential to a buying arrangement for geopolitical and strategic purposes.

Securing key permits may provide offtakers the degree of certainty needed to move forward with inked agreements. For blue ammonia in particular, Class VI permitting would almost certainly be a prerequisite for FID. The Class VI permit gives offtakers a degree of certainty that the geology and injectability for the project is appropriate and that it has the license to operate.[1] Developers that feel confident in their project’s geologic characteristics for CO2 sequestration and the eventual receipt of the Class VI permit may be willing to proceed with conventional production. This willingness would depend on the structure of their sequestration relationship and a known market for that conventional production.

The large-scale infrastructure required of an ammonia facility is likely to require a host of other permits to facilitate construction and then regular operations of the completed facility. These other permits, however, may not entail the same costs associated with the Class VI permit (in terms of producing the required documentation for a complete application) and timeline for procurement.

Such permitting may include marine construction permits for docks and pilings, permits to deepen drafts to allow larger ships access to a given facility, and for the disposal of those dredged materials. The plant itself may require a new source review permit to limit air emissions. For a greenfield facility, receipt of such a permit would occur before the onset of construction. In Texas, for instance, an air quality permit is needed from the Texas Commission on Environmental Quality. A state-level pollutant discharge elimination system permit may also be necessary. In some localities, an objectionable use permit may be required if proposed use of the property could be objectionable to neighboring properties, such as from traffic or exhaust.

The environmental reviews and regulation we previously cited as potentially applicable to long-haul carbon dioxide pipeline development, may also apply to these large-scale projects. Particularly, the National Environmental Policy Act (NEPA) comes into force if there is federal involvement, if a project crosses federally controlled land or waterways, uses federal funds, or affects air or water quality regulated under federal law.

Notably, there are no major federal-level permits required for the export of ammonia to determine if the project is in the US public interest, as is the case with LNG export facilities.

[1] To read more about the Class VI permit process, please refer to our previous publications on carbon capture and sequestration.

As we discussed in our recent article highlighting the opportunities and roadblocks in the US carbon capture market, the differentiated product market is nascent. In some cases, long-term contracting may seem premature without Class VI permits, independent engineer assessments of the suitability of the project’s pore space for injection, or nearer-dated clean ammonia production. To date, offtake commitments to announced clean ammonia facilities generally have taken the form of non-binding contracts, memorandums of understanding, heads of agreement, and the like.

Some recent announcements have focused on collaborations for offtake. CF Industries and POET announced a pilot project for POET’s offtake of low carbon ammonia to lower the carbon intensity of ethanol and corn production. POET’s suppliers are targeting start of use of those supplies this autumn and next spring. As of now that supply will be from the Donaldsonville Complex’s green ammonia. That collaboration involves monetization opportunities for farmers using that low-carbon product and working with fertilizer retailers. PepsiCo and Yara recently signed a deal for Yara to provide volumes of green and blue ammonia from its European facilities to be delivered alongside conventional ammonia.

A fully developed export-oriented clean ammonia market also raises the question of the potential entrance of marketers for any net length in product or trading optimization. The need for such capabilities will likely hinge on how many traders enter the market.

US clean ammonia could reach European fertilizer markets, driven by a combination of IRA tax credits underpinning US producers and the EU’s CBAM. While CBAM will help encourage supply to head to Europe, RED III industry quotas could also spur European imports of clean ammonia. Some European players have also sought ammonia interoperability with their existing assets, especially those hoping to potentially repurpose LNG import facilities into so-called “multi-molecule” assets in the future.

Existing ammonia value chain participants seeking to reduce their emissions may be looking for emission reductions. To the extent that these participants can pass along some of the costs to product end users in the food value chain, clean ammonia use may be a viable option.

Other potential uses of clean ammonia are for co-firing in the power sector and as a clean fuel for the maritime market. Where clean ammonia will not directly substitute conventional ammonia, the economics, feasibility, and viability of use will be tied to the cost of supply, both in terms of outright price, but also in terms of the conversion losses that increase the cost of use.

Some announced projects have noted the potential to market their products to Asia, either implying or directly stating for clean ammonia use in the power sector. That use could be either as a direct ammonia blend or require the ammonia be cracked back to hydrogen for a blend of that fuel. South Korea and Japan each have programs to encourage ammonia co-firing in coal plants, hydrogen co-firing in natural-gas-fired plants, and in some-cases, for industrial uses.

In some cases, the governmental push to support the use of clean ammonia or clean hydrogen is helping to bridge the supply-demand gap by subsidizing cost and underpinning long-term contracting. However, the extent to which governments commit to help bridge the incremental cost – for how long, what number of contracts, what volumes, and what repeatability – are all critical to how much impact these programs will have in the long run.

The Japanese Ministry of Economy, Trade and Industry (METI) is slated to set up a contract-for-differences style program for hydrogen procurement. This supply-side program is intended to offset the differential between a fossil fuel and its replacement differentiated product. Additional program details are expected ahead of the application opening, which is expected this winter.

South Korea’s Ministry of Trade, Industry and Energy (MOTIE) announced in late May that it would auction 15-year power purchase agreements for contracting, beginning in 2028 with domestic utility companies. Importantly, while there are four tiers of emissions intensity, variable pricing mechanisms must be based on Henry Hub. Though these prices can be fixed or variable, the linkage back to benchmark US natural gas prices would appear to underscore a potential presumption that US supply will feature prominently in the program as well as blue supply.

Singapore’s Energy Market Authority has proposed emissions standards for power plants that include a hydrogen compatibility requirement. New and repowered plants must be at least 30% hydrogen blend compatible and capable of being retrofit to 100% hydrogen compatibility in the future. Singapore also plans to build hydrogen-ready gas-fired power plants. Currently, nine new hydrogen-ready plants are in planning stages.

Offtakers’ carbon intensity requirements will ultimately impact project cost. The setting of carbon intensity targets will impact the degree of investment clean ammonia producers are willing to make as producers will want to “right-size” their infrastructure investment to meet those requirements. The emissions-intensity of ammonia will be linked to the process by which hydrogen is formed. Hydrogen produced in the US today is dominated by steam methane reforming (SMR), which accounts for nearly all of the ~10 MTPA of operational hydrogen capacity in the US. This means SMR is likely to be the technology behind projects retrofitting existing capacity with carbon capture. The emissions intensity of the SMR pathway will depend on whether there is installed carbon capture for the flue gas. That installation not only significantly reduces the emissions intensity of the project, but also comes with a significant increase in capital cost. Investment decisions around whether to install carbon capture for the flue gas will be directly tied back to what the differentiated product market is demanding.

Autothermal reforming (ATR) produces a higher-purity CO2 stream than SMR. Its process generally avoids the need for flue gas carbon capture. Given that SMR is the dominant hydrogen production pathway in the US currently, ATR-pathway ammonia in the US is likely to be greenfield.

It is not yet clear if offtakers will regionally align on a carbon intensity specification to allow for marketing opportunities at times of supply length.

A large-scale buildout of export-oriented facilities will require additional shipping capacity, given ammonia’s high concentration in integrated processes today. As of 2022, there are some 40 vessels dedicated to ammonia transport and an additional 170 vessels capable of transport, per the International Renewable Energy Agency (IRENA). The latter are mostly comprised of liquefied petroleum gas carriers. These can be fully refrigerated, semi-refrigerated, or kept under pressure. Today, typically traversed routes see ship sizes from 10,000-35,000 cubic meters.

LPG tankers and potentially LNG vessels could be repurposed to carry ammonia. However, they may continue their existing service, as the buildout of both LPG and LNG export capacity is underway. Shipbuilder order books are growing for ammonia carriers. Costs can range from roughly USD 60-120 million per vessel, and delivery can take to two to three years. Various sizes of ships are reportedly on order, including very large ammonia carriers (VLACs) with capacities near 90,000 cubic meters, significantly larger than the vessels in service for ammonia today.

Though numerous VLACs are on order for ammonia, it is unclear if such large capacity will be the sizing the marketplace requires. Both the exporting and importing facility (and their docks) must be able to handle such a ship. The importing and exporting facility must also have sufficient storage capacity to accommodate the capacity.

Shipbuilder order books may not be an ideal barometer for future ammonia market growth. In some cases, buyers are paying additional charges for the optionality to be in service as either a VLAC or very large gas carrier (VLGC).

The scale of announced projects suggests there is momentum behind clean ammonia. However, the degree to which a differentiated market develops will ultimately govern how many projects reach FID. The relative lack of maturity of the clean ammonia market and the unknown differentiated ammonia premium along with development costs have given some potential project developers cause for pause. These issues have specifically been cited in electing not to move forward with some projects. Some companies may be comfortable being among the first to market, but they are also likely to have existing offtake relationships. This will not be the case for all proposed projects.

The growth trajectory of blue ammonia (and the broader clean ammonia category) will be underpinned by how robust growth in alternative ammonia use is. Given the nascency of the product, its lack of differentiated market and the relative lack of a clear (or still in flux) demand-side regulatory framework, we anticipate only a portion of announced capacity reaches FID. Because there still is a viable market for conventional production, in many cases that capacity has the optionality to be retrofit at a later time. That optionality gives those projects the ability to arbitrage if a differentiated product market forms. Large-scale US projects appear to have a key role to play in the evolving clean ammonia market, especially if time-to-market is a concern, with retrofit of existing capacity and a network of infrastructure to support production.

Multiple considerations contribute to a positive FID. Being positioned strategically for export market access, shipping efficiencies, the ability to leverage existing assets in the value chain (or permits for them), and the presence of binding offtakers all are key success factors.