An alternative future for LNG infrastructure

The conversion of LNG infrastructure to handle hydrogen holds promise, but it also presents some significant technical and of Kobe, although others are planned in South Korea and Australia.

However, US company Chart Industries says that its integrated pre-cooled single mixed refrigerant mid-scale modular liquefaction technology could be used to liquefy hydrogen with some adjustments. Moreover, it estimates that it would be at least 50% cheaper to convert existing LNG infrastructure to liquefy hydrogen than to build dedicated new hydrogen liquefaction projects.

Some LNG producers, such as Cheniere Energy and Sempra Energy, have already expressed an interest in entering the nascent market for internationally-traded hydrogen.

Liquefying hydrogen requires chilling it to -253°C, significantly lower than LNG’s 161.5°C, a factor expected to add to both liquefaction and vessel costs. Moreover, liquefying natural gas consumes less than 10% of its energy, but this proportion increases to about a third for hydrogen. At 3.5 kWh/m3 hydrogen is less dense than natural gas (11.4 kWh/m3), so the same volume would contain far less energy, meaning that more carriers would be needed.

This could make the cost of seaborne trade in hydrogen challenging to bear. The International Renewable Energy Agency, for example, thinks that trade in hydrogen by 2050 will be roughly equally divided between pipeline delivery and ammonia carriers. Ammonia is corrosive and toxic, but has lower thermal insulation requirements than LNG as it becomes liquid at only -33°C.

Cost estimates uncertain

Neil Ford

LNG’s role in the energy transition remains in the balance. Security of supply concerns have solidified its bridging position, and the fuel remains essential for the reduction of coal-fired generation, notably in Asia, and as a stabilising generation source for variable renewables. However, to safeguard its longer-term role, developers, both on the export and import side, are assessing the integration and conversion possibilities for lower-carbon liquified gases such as hydrogen and ammonia.

These efforts aim to address concerns that new LNG import infrastructure – which is being rapidly deployed in Europe in the wake of Russia’s war in Ukraine – will be stranded or perpetuate the use of unabated natural gas. Converting LNG infrastructure for hydrogen and/ or ammonia use could future-proof new LNG investment needed today and reduce the costs of the energy transition by efficiently re-using existing assets.

Conversion possibilities

The main focus for LNG infrastructure centres on the possibility of converting existing LNG export and import terminals and vessels to handle hydrogen and ammonia shipments.

In liquid form both hydrogen and LNG projects need cryogenic equipment, but the International Energy Agency says that the conversion of existing or planned LNG infrastructure is “technically challenging” and “requires replacement or drastic modification of most of the equipment”. At present, there is only one small prototype liquid hydrogen import terminal – at the Japanese port

The lack of existing conversion, liquefaction or regasification projects means that it is difficult to estimate costs. However, a study by the Fraunhofer Institute for Systems and Innovation published in November 2022 on behalf of the European Climate Foundation, estimated that about 70% of LNG import terminal investment could be used within a converted ammonia terminal, falling to 50% for conversion to liquid hydrogen, based on the cost share of the LNG tank.

The Fraunhofer Institute recommended that LNG import terminals be designed at the outset to be easier to convert to hydrogen or ammonia, including by building storage tanks out of compatible materials such as special stainless steel.

This is particularly important as storage tanks are the most expensive element of LNG import terminals.

Moreover, “additional thermal insulation of the tank is required or a higher boil-off has to be accepted” on liquid hydrogen conversion, the institute said.

Japan’s IHI Corporation is considering converting its LNG import terminals and storage facilities to handle ammonia sometime between 2025 and 2030. IHI aims to use ammonia as a thermal power plant feedstock, describing it as “a carbon neutral alternative to coal and gas-fired power plants because its combustion emissions are free of carbon dioxide”. It added: “Converting LNG facilities should drive ammonia uptake by slashing costs and ensuring effective land usage.”

Pipelines currently used for natural gas transport would also have to be converted to handle the different temperatures and pressures of hydrogen and ammonia. Fittings and valves are usually designed for specific operating conditions and so must be technically sealed to handle hydrogen, as hydrogen molecules are smaller than those of methane, or indeed than any other molecule, and leaked hydrogen would fuel climate change, as well as pose safety concerns.

Control valves have to be recalibrated to limit the hydrogen leakage rate, while helium can be used to test for potential leaks. Connecting parts can also be welded together and checked via x-ray radiation. A fracturemechanical inspection of the steel is needed in hydrogen pipelines, but not for natural gas pipelines, as hydrogen has a 20-30 times higher crack growth rate, according to the Fraunhofer Institute.

Dutch natural gas infrastructure operator Gasunie recommends using only high alloy chromium nickel steel to manufacture hydrogen pipelines to avoid hydrogen embrittlement, increasing costs slightly in comparison with natural gas pipelines. Pipelines also have to be kept very clean, such as by using dry ice, to avoid hydrogen contamination.

Finally, pipeline flow velocity has to be increased as hydrogen and ammonia are less dense than natural gas. Natural gas pipelines have a pressure level of 70-100 bar depending on age, but hydrogen pipelines need to be up to 100 bar.

Ammonia technologies tried and tested

Current enthusiasm for ammonia is based on using it as a fuel, particularly in shipping, although it is currently mainly marketed as fertiliser. However, it could also be converted back into hydrogen for use as a motor fuel, in heating and in steel production and other industrial applications. Converting hydrogen to ammonia in the export country and back again in the intended market would require investment in cracker equipment, which would require more investment and consume more energy.

Ammonia is easier to liquefy and has a liquid energy density partway between that of LNG and hydrogen. There is already some seaborne trade in ammonia. The Fraunhofer Institute and BNEF have concluded that conversion of LNG terminals into ammonia terminals is technically and financially feasible, with BNEF estimating 6-20% additional investment to achieve ammonia retrofitting.

In a report on converting LNG import terminals to handle ammonia, Black & Veatch said that storage tanks can be modified to hold ammonia, although they would have lower working capacities. In addition, it recommended the boil-off gas (BOG) system be fully evaluated to identify the proper compressor configuration to avoid inefficient BOG compressor operation. Finally, it said that the instrumentation and measuring devices should “be evaluated in detail to ensure their functionality with ammonia”, with some components replaced.

According to the Ammonia Energy Association, ammonia can be transported by pipeline at half the cost

DESIGN ®

of natural gas because of the smaller pipeline diameter required. By comparison, it estimates hydrogen pipeline transportation costs at double those of natural gas and so four times those of ammonia pipelines. Although there is currently no European ammonia pipeline network, the US network already extends to over 4,800 km and carries 2 MTPA, mainly for the fertiliser industry. As such, ammonia use at industrial scale is tried and tested.

Moreover, the technical and economic challenges posed by converting LNG infrastructure to hydrogen and ammonia use have to be seen in the context of both the high cost of hydrogen production by electrolysis using renewable power and the need it would create for additional renewable generation capacity. Emissions from producing hydrogen from natural gas can be addressed through carbon capture and storage and at a lower cost than current electrolysis technologies.

As a result, how the future production and distribution of low carbon gases evolves is highly dependent on the economic cost trajectories of numerous, often competing, technologies. But given its scale and the experience of liquid gas handling, the LNG industry is well placed to play a major role, leveraging existing assets to create new supply chains based on existing infrastructure investments.

‘To be or not to be? That is the question. Whether ‘tis nobler in the mind to suffer the slings and arrows of outrageous fortune, or to take arms against a sea of troubles, and, by opposing, end them? -

Hamlet, Shakespeare

Europe is in a quandary about whether to sign up longterm LNG contracts or to depend increasingly on spot purchases and portfolio supplies. Thus far European buyers have been relatively reluctant to sign long-term LNG contracts. And as a result of their reticence, it is the so-called ‘aggregators’ or portfolio players who are currently underwriting many of the long-term LNG offtake contracts needed to underpin liquefaction investments. Europe faces the proverbial prisoner’s dilemma: If too many European players underwrite more long-term supply, it could tip the global LNG market to oversupply in the late-2020s, which would cause prices to drop and leave those very contracts out of the money. However, if Europe avoids contracting for more long-term offtake, aggregators will potentially have growing leverage over European buyers. The dilemma is more acute since there is a trade-off to be made between contracting for shorter or for longer tenures. If Europeans do not wish to take on long-term commitment given expectations of declining demand for natural gas, they could negotiate shorter- term deals with the aggregators — but that comes at a mark-up.

It has been striking that Europe’s direct role in the recent resurgence in global LNG contracting has been relatively minor despite the Russian–Ukrainian crisis. Rather, Asian buyers and aggregators (consisting of IOGCs and traders) have been the biggest participants signing up for offtake capacity since 2021.

More recently, the G7 discussions regarding a possible halt or ban on Russian gas imports to Europe, including LNG, have added greater urgency to the question of whether Europe should increase its direct long-term offtake of non-Russian LNG.

At the heart of this discussion is Europe’s challenge to meet its longer-term decarbonisation goals while ensuring security of energy supply. Given Europe’s aggressive decarbonisation plans, European buyers are uncertain about future demand and are therefore hesitant to make long-term LNG offtake commitments. Additionally, European utilities face a lack of legal clarity regarding their residual contractual commitments to take Russian pipeline gas, which is further discouraging Europe from signing up for long-term LNG supplies.

Data compiled Jun. 05, 2023. Pre-FID at ttime of contract signing. Source: S&P Global Commodity Insights. 2023. © S&P Global.

European buyers account for just 10% of the 96.5 MTPA signed globally in pre-FID firm offtake — comprising sale and purchase agreements (SPAs) and liquefaction tolling agreements (LTAs) — since the start of 2021, based on assumed destination. By comparison, Asian buyers make up 44%. However, portfolio buyers with multiple assumed destinations also account for 44%, indicating that these volumes can become available as needed to Europe or other markets over time (see figure 1).

For projects within the United States, which has led the recent global contracting rebound from the supply side, Asian end-users make up nearly 40% of the 61.6 MTPA in firm offtake (SPAs) contracted by third parties for pre-FID US projects (at the time of signing) since the start of 2021. IOCs and trading firms together account for a further 30%. European end users represent 19%, which is a material share, but is half that of Asian end users (see figure 2).

Moreover, if we focus on more recent deals since the start of the Russia–Ukraine crisis, aggregators took the biggest share signed since the start of 2022, accounting for 35% of US pre-FID projects’ firm contract signings (see figure 3).

This strong demand for US supply is supported by the liquid US natural gas market, favorable price differentials at Henry Hub versus markets in Europe and Asia, and the flexible destination contracting offered by US project developers.

Data compiled Jun. 05, 2023. Pre-FID at ttime of contract signing. Source: S&P Global Commodity Insights. 2023. © S&P Global.

Europe takes the plunge

Some European players have taken the plunge. They have contracted LNG from four US export projects since the start of 2021: Venture Global’s CP2 LNG and Plaquemines LNG, Sempra’s Port Arthur LNG, and NextDecade’s Rio Grande LNG. All these deals are for FOB delivery, which means that the offtakers must arrange shipping and have the flexibility to deliver those volumes to their destination.

By opting for FOB supply, new market entrants are having to make a splash into LNG tanker newbuilds. Moving into shipping is a major step in terms of both financial commitment and operational skill-set. Also, the sector may have strong economies of scale difficult for a buyer to exploit. Take as an illustrative example, EnBW’s 2 MTPA of offtake from its Plaquemines LNG and CP2 LNG SPAs, which will require long-term charter agreements for four tankers to service these contracts. RWE’s 2.25 MTPA of offtake will require up to three tankers. These shipping arrangements are sufficient to cover delivery to Europe but not necessarily sufficient by themselves to support switching opportunistically to distant Asian markets. More established market participants, such as Engie, are utilising their existing fleets and adding to it in order to service their various offtake agreements.

Chartering and operating a fleet of LNG tanker will not make sense for all buyers, or even be affordable.

The evolving US LNG model: FOB to DES?

Meanwhile US LNG project developers also are looking to cut out the aggregators by moving into shipping. This dynamic may reflect developers’ ambitions to offer Delivered Ex-Ship (DES) LNG contracts to buyers who are not interested or are unable to take a shipping position. This offering could help secure further SPA signings and differentiate some US Gulf Coast LNG projects from others. It could unlock new buyers in Europe reluctant to assume the shipping commitments. In the past, we have seen some project developers such as Cheniere expand across the LNG value chain and take positions in shipping and regasification terminals, becoming fully integrated. Additionally, project developers can use surplus production volumes that are not assigned to long-term offtakers to take advantage of market opportunities.

Shipping gives the seller a significant level of optionality, which in a growing spot LNG market can increase trade margins substantially. This dynamic became quite evident during the run-up in spot LNG prices during the second half of 2022, when having access to shipping options gave FOB buyers the flexibility to seek the highest paying market. LNG project developers were able to benefit from the incredibly high spot LNG prices during 2022, due to their shipping fleet. Considering the four US projects for which European buyers signed pre-FID firm offtake in 2021–23, the potential peak export volumes surpass announced nameplate capacity by nearly 18 MTPA.

• Venture Global has five 200,000-cbm vessels on order, which equates to an estimated 3–3.2 MTPA (assuming a 50/50 split in deliveries between Northeast Asia and Northwest Europe). That surpasses the company’s requirement to fulfil its only announced DES contract to date, a 1.2 MTPA DES SPA with Sinopec. This situation may indicate that Venture Global plans to sell volumes for its own account. This strategy is a departure from the other US Gulf Coast project developers which so far are more narrowly focused.

• Sempra Infrastructure, in contrast, has no announced new ship-build orders or charters associated with its Port Arthur LNG project, which has signed only FOB deals to date.

• NextDecade’s Rio Grande LNG project has signed one DES contract to date — a 1 MMtpa SPA with Guangdong Energy Group — out of 10.8 MTPA in firm offtake contracts. Where disclosed, the project’s other offtake contracts are FOB.

Conclusion: The battle for midstream control

Aggregators are performing an important role. They provide the long-term underpinning to enable new FIDs of LNG projects. However, both project developers and buyers are wondering whether to rely upon them or whether to consider taking on an extended role themselves to avoid the ‘slings and arrows’ of volatile spot markets.