Listen: Greening steel production and hydrogen’s potential

Seoul — South Korea’s major business conglomerate SK Group said Jan. 7 it will invest Won 1.6 trillion ($1.5 billion) in US fuel cell maker Plug Power Inc., a move that will help the company expand its hydrogen footprint.

The plan by SK Group, which runs the country’s biggest oil refiner, is seen as an effort by the company to have a bigger presence in the carbon-free fuel sector and diversify its energy mix at a time when South Korea is aggressively pushing ahead with energy transition plans.

Under the deal, SK Holdings, the group’s holding company, and SK E&S, a natural gas subsidiary, will acquire a combined 9.9% stake in Plug Power, with the strategic investment making it the biggest shareholder, SK Holdings said in a statement.

SK Holdings and SK E&S will each contribute Won 8 billion for the stake in Plug Power, which has provided 40,000 fuel cell systems for electric vehicles and has built and operated hydrogen filling stations across North America.

“The deal is expected to be finalized in the first quarter,” a company official said. “The investment is aimed at boosting the group’s leadership in Asia’s hydrogen market,” he added.

Under the deal, the SK units and Plug Power will form a joint venture in South Korea to provide hydrogen fuel cell systems, fueling stations and electrolyzers to the Korean and broader Asian markets, such as China and Vietnam, the official said, without providing details of the timeline. Electrolyzers use electricity to break water into hydrogen and oxygen.

SK Group runs South Korea’s biggest oil refiner and major battery maker SK Innovation and SK E&S, an LNG-based private power utility and city gas provider, among others, launched a taskforce for tapping into the hydrogen sector last year.

The group aims to have a hydrogen production capacity of 30,000 mt/year in 2023 and 280,000 mt/year by 2025 and establish a value chain ranging from production to distribution and supply.

OVERSEAS AMBITIONS

In pursuing overseas ambitions, SK Group joins Hyundai Motor, which is considering building its first overseas hydrogen fuel cell systems plant in Guangzhou, China, according to a company source.

South Korea’s biggest automaker has been betting on the hydrogen fuel cell electric vehicle, or FCEV — a rival technology to internal combustion engines — and plans to invest Won 7.6 trillion along with its local partners by 2030 in order to produce 500,000/year hydrogen-powered vehicles under its “FCEV Vision 2030.”

The corporate investments in hydrogen come as South Korea’s President Moon Jae-in declared last October that the country will achieve carbon neutrality by 2050 by replacing coal-fired power generation with renewable sources and internal combustion engine vehicles with hydrogen-powered and battery-based electric vehicles.

From setting up the biggest liquid hydrogen plant in the world to producing the carbon-free fuel as a byproduct, South Korea is fast implementing new technologies to expand the scope of hydrogen production as it bets on robust growth prospects.

The country currently imports 100% of its crude oil needs. Under its roadmap for a “hydrogen economy,” South Korea will produce 81,000 hydrogen-powered cars by 2022, which will increase to 6.2 million units by 2040, which is significant given South Korea has a total of 22 million vehicles on the road currently, using mainly gasoline, diesel and LPG as fuel.

The blueprint also calls for the country to supply 15 GW of hydrogen fuel cell capacity for electricity production by 2040, of which 8 GW will be for domestic use. The 8 GW capacity is about 7% of South Korea’s combined power generation capacity of 116 GW.

London — Low-emission steelmaking costs in Europe remained high in 2020, based on high iron ore pellet prices and green hydrogen cost assumptions, with potential for natural gas-based direct-reduction iron improving on lower gas prices, according to an S&P Global Platts analysis.

EU market carbon prices last year averaging around Eur24.50/mt ($30.08/mt) were not high enough to significantly narrow cost differences between blast furnaces and DRI. Major raw materials inputs for blast furnace-based steel, accounting for around 2.2 mt of carbon per ton of steel, were far lower than theoretical DR iron ore pellets and renewables-based green hydrogen for DRI.

Even with far higher carbon prices, a sizable cost gap remains, leading to a discussion on government support and mechanisms enabling green steel works and energy infrastructure to get off the ground.

This was based on Platts prices for steel raw materials and energy assessments in the Netherlands, which is a major receiver of coal and iron ore.

Blast furnaces use met coke as the main reductant energy, with low coking coal prices last year helping mitigate higher iron ore costs.

Natural gas prices in the Netherlands were particularly low last year between April through July on lower global industrial activity during the height of the coronavirus pandemic, with manufacturing and services adapting to the initial wave with falls in demand.

HYBRIT

Ferrous scrap-based electric arc furnace plants were supported by low power prices and weaker continental European scrap prices in mid-2020.

Lower gas and power prices helped pull down DRI cash costs for processing by electric arc furnaces. ArcelorMittal operates the region’s only commercial natural-gas based DRI plant in Hamburg, while SSAB and LKAB’s HYBRIT pilot green hydrogen DRI plant operates in Sweden.

New DRI plants are expected to boost demand for iron ore pellets, with up to 13.8 million mt/year of DRI reliant on seaborne pellets coming on stream by 2030, including projects from Salzgitter and ThyssenKrupp, according to December estimates from the International Iron Metallics Association.

Existing DRI plants run on natural gas and thermal coal, and are mainly in the Middle East and North Africa, India, Russia and in the Americas region. A lack of lower cost gas supply in western Europe has so far limited DRI plants, even though new projects are mulled in Italy, Romania and Germany, even if they transition to hydrogen in future.

Most of the new DRI capacity outlined by IIMA is in Europe and North Africa, with China’s HBIS producing 600,000 mt/year later this decade.

According to the International Energy Agency’s steel carbon emission data published in October 2020, blast furnace-based steel accounts for around 2.2 mt of total emissions per ton of steel, with natural-gas based DRI and EAF steel comprising 1.4 mt in total emissions, and ferrous scrap-based EAF at 0.3 mt of total emissions.

Steel emissions are dependent on raw materials qualities and preparation, and energy origin through the chain, complicating benchmarking.

Combinations and overlapping usage of metallics and scrap with pig iron in the integrated route and EAF may be adopted, both to lower emissions and test scenarios for bigger changes to operations.

Hydrogen

Platts publishes global hydrogen prices, and in the Netherlands assesses PEM Electrolysis hydrogen, Prices are based on the cost of hydrogen, and a separate series including the higher costs of including fixed capital, operating and water costs, and the variable feedstock cost of electricity.

Even with lower electrolyzer capital costs in the future, the impact on hydrogen’s price competitiveness may be limited longer-term compared with fossil-fuel based gray hydrogen or blue hydrogen, which relies on carbon capture and storage, and with natural gas.

While green steel production costs look much higher than existing DRI, EAF and blast furnace routes, even with higher prices for carbon, the price premium commanded for low- and zero-emission steel product sales may need to be evaluated.

Benchmarking green steel and metal prices and premiums by the costs via each steelmaking or smelting route, as well as supply and demand for such steel and aluminum products, is underway.

ArcelorMittal, Salzgitter, Rusal and GFG Alliance/Liberty Steel are among companies commercializing low-emissions metals.

Markets are evolving where increasingly there is a metals and energy procurement motive for overall emission reduction goals. A shift away from a sole focus on markets-based supply by cost with power and carbon prices may be seen.

Pure hydrogen (H2) is increasingly seen as a tool for decarbonization in a wide range of industries. But in order to break into the mainstream, the fuel will need reliable methods to transport it.

While current demand for H2 is limited primarily to oil refining and chemical production – mainly ammonia and methanol – there is growing consensus that H2 could serve as a key decarbonization approach in an array of commercial, power generation, transport and industrial applications.

Reliable, sustainable, and cost-effective transportation of H2 to where it is needed is a prerequisite to the competitiveness and uptake of H2, as centralized production is likely to dominate supply in the near to medium term.

S&P Global Platts Analytics’ recent report Pumping Protons: The Landscape of Transporting Hydrogen, explored both mature and cutting edge transportation pathways for H2, assessing feasibility and impacts on price.

Go deeper: Request a copy of Pumping Protons: The Landscape of Transporting Hydrogen

Hydrogen pipelines

As of 2016, there were over 2,800 miles of dedicated H2 pipeline installed globally, with 1,600 miles in the US. This is in contrast to over 130,000 miles of onshore oil pipelines and 300,000 miles of onshore natural gas pipelines in the US alone.

Due to their high capital cost and long lifetime, H2 pipelines are typically reserved for high volume flows with stable and long-term demand of 15-30 years. This use case is most typical in the chemical and refining industry, sectors which own and operate the bulk of current installed pipeline capacity. At low flow volumes, pipelines are typically not cost effective.

Natural gas pipelines

Blending H2 into existing natural gas pipeline networks would allow for pipeline H2 transportation without new dedicated pipes. Blended H2 can either be removed at city gate pressure step-down facilities, or left as a constituent of the natural gas.

While leaving H2 blended in the natural gas stream can reduce costs, it can also cause challenges for end-use infrastructure such as natural gas burners and turbines. To address this, some jurisdictions have defined H2 blend limits in natural gas pipeline system.

Platts Analytics estimates that a global 5% blending of zero carbon H2 into the gas grid could abate up to 340 MT CO2 per year – equal to the total annual GHG emissions of a country like Spain.

Gaseous tube trucks

Gaseous hydrogen (GH2) can be transported by heavy duty trucks in small quantities in compressed gas containers, known as tube trucks. GH2 tube trucks use several pressurized gas cylinders, or tubes, bundled together on large trailers.
Tube trucks are commonly employed for transporting H2 to sites with low and intermittent demand such as light-duty vehicle H2 refueling stations. Compressor loads are a primary cost contributor to GH2 transportation.

Liquid hydrogen trucks

Liquefaction is an energy-intensive, multistage process with costs exacerbated by H2 having the lowest boiling point of any element, requiring temperatures below -253oC to enter into the liquid phase, compared with around -160oC for LNG.
Liquefied hydrogen (LH2) is stored in large, insulated containers at terminals before loading onto insulated trucks. In its liquid state, a single truck can haul up to 3,500 kg of LH2, over three times the haul-per-load of a GH2 tube truck.

This requires significant investment in a liquefaction terminal, highly-insulated storage tanks and truck trailers, and regasification terminals at destination. At the same time, it saves money on high pressure storage and operational transportation costs.

Due to the high capital investment required to set up a liquefaction plant, LH2 delivery is typically saved for medium- to high-demand volumes consistent enough to validate the investment, but below volumes that justify a pipeline. Many supply chains feeding H2 refueling stations in California are utilizing liquefaction to increase volumes.

International shipping

Marine hydrogen trade provide countries the opportunity to diversify their energy imports with low carbon fuels, particularly for regions that have domestically constrained natural resources.
Similar to LNG, H2 could be liquefied at port terminals before being loaded onto highly-insulated tanker ships. Based on assumptions about volumes of current LNG tankers and LH2 density, dedicated LH2 ships would likely have a carrying capacity of between 12,750-18,400 tonnes H2/ship.

Boil-off of product is a key concern, even when utilizing bunkers with active cooling measures. On an eleven-day journey (typical of a bunker trip from Australia to Japan), an LH2 ship could experience losses of 2% of cargo, though a portion could be utilized for ship propulsion (similar to LNG bunkers).

H2 need not be produced internationally to be sourced from international energy sources. To avoid the headache of transporting H2 on dedicated marine bunkers, market participants could leverage LNG’s vibrant and lower-cost international trade network to import LNG as a feedstock for the production of H2 in-country. While this pathway is likely much lower cost, it requires domestic access to both domestic LNG regasification facilities, hydrogen production facilities with carbon capture, and geologic storage for captured CO2.

Future hydrogen transport

Next-generation H2 transportation pathways increasingly look to simplify transportation by chemically incorporating H2 into larger molecules that exist as liquids at or near ambient temperature and pressure.
LHCs are much denser than GH2, allowing for greater mass of H2 per unit volume without the liquefaction and insulation challenges of LH2. LHCs also change the chemical properties of H2, alleviating some transportation concerns, though often in exchange for toxicity concerns.

Several LHCs are under consideration, including ammonia and methanol. Conversion of H2 to ammonia requires 7%-18% of the energy within the hydrogen. While use of LHCs has multiple theoretical benefits, the practice has yet to gain traction due primarily to conversion costs.

Up to now, H2 pipelines and liquefied trucking have proved to be low cost and reliable modes to service current H2 demand. Ambition to diversify both production and demand into novel low-carbon pathways will require a rethinking of the H2 supply networks we rely on today.

As ESG factors become increasingly important to governments and companies around the world, hydrogen has solidified as a means to divest from fossil fuels across commercial, power generation, and transportation industries. Although it is not yet a perfect solution, as most hydrogen today is produced from fossil fuels, the global community is racing to research and implement hydrogen within the energy mix in efforts of accelerating the energy transition and achieving net-zero emissions.

Tokyo — Japan is set to enter new era of hydrogen development in 2021 as it launches the world’s first transport of liquefied hydrogen from Australia, a key step forward in the commercialization of a potential new source of energy.

The start of liquefied hydrogen transport over 9,000 km will come at a time when there is unprecedented momentum for the deployment of hydrogen as a key energy source in Japan after Prime Minister Yoshihide Suga said on Oct. 26 that the country would now aim for carbon neutrality by 2050.

“This is an important milestone for creating international hydrogen supply chains in the future,” Toshiyuki Shirai, director of advanced energy system division & hydrogen and fuel cell strategy office at the Ministry of Economy, Trade and Industry, told S&P Global Platts.

“We hope to see vigorous moves towards further utilization of hydrogen in various sectors,” Shirai said on a recent launch of the Japan Hydrogen Association, or JH2A, to develop a hydrogen supply chain and promote its greater use as a potential new source of energy.

The transport of the liquefied hydrogen will take place as part of a pilot project run by the CO2-free Hydrogen Energy Supply-chain Technology Research Association, or HySTRA, with aid from the state-owned New Energy and Industrial Technology Development Organization.

The project will demonstrate in fiscal 2020-21 (April-March) brown coal gasification and hydrogen refining in the Latrobe Valley in southeastern Australia; hydrogen liquefaction and storage of liquefied hydrogen at the port of Hastings; marine transportation of liquefied hydrogen from Australia to Japan and the unloading of liquefied hydrogen at Kobe.

The exact timing of the maiden transport of the liquefied hydrogen on the 8,000 gross tonnes Suiso Frontier, the world’s first liquefied hydrogen carrier with a cargo loading capacity of 1,250 cu m, remains unclear.

The Suga cabinet decided its draft budget Dec. 21 for Japan’s 2021-22 fiscal year, including the Yen 4.75 billion ($45.88 million) requested by METI for the transport of liquefied hydrogen between Australia and Japan, meaning the transport of liquefied hydrogen will likely take place in the next fiscal year upon approval by the Diet.

GOLDEN AGE

The carriage of liquefied hydrogen will be the third method introduced to transport hydrogen from abroad to Japan, where it aims to develop and commercialize supply chains by 2030 under its basic hydrogen strategy set in 2017.

With Japan having developed three ways of importing hydrogen and testing underway for each option, the country is entering a new phase of the hydrogen economy, said Nobuo Tanaka, former executive director of the International Energy Agency.

“2021 will be the first year of the golden age of hydrogen,” said Tanaka, who is currently chairman of the steering committee of the Innovation for Cool Earth Forum, or ICEF.

“It is important that Japan should pursue both options of expanding blue and green hydrogen,” Tanaka said, adding that the country could develop its supply chain, producing hydrogen from using upstream gas at LNG projects in the future.

Blue is commonly used for hydrogen production from fossil fuels with carbon dioxide emissions reduced by the use of carbon capture, utilization and storage, or CCUS, with green applying to hydrogen production from renewable electricity and gray referring to hydrogen production from natural gas, according to the IEA.

HYDROGEN TRANSPORT

In May, Japan’s Advanced Hydrogen Energy Chain Association for Technology Development, or AHEAD, launched its pilot project to bring hydrogen using toluene into methylcyclohexane (MCH) using gas from the Brunei LNG liquefaction process to Tokyo Bay for use as a power generation fuel, the world’s first supply chain for foreign-origin hydrogen.

It was followed by the import of the maiden blue ammonia cargo in October from Saudi Arabia to be used for power generation, with CO2 capturing process designated for use in methanol production at SABIC’s Ibn-Sina facility, as well as captured CO2 being used for Enhanced Oil Recovery at Saudi Aramco’s Uthmaniyah field.

Ammonia, a compound consisting of three parts hydrogen and one part nitrogen, contains about 18% hydrogen by weight and is already a widely traded chemical globally, and it releases zero CO2 emissions when combusted in a thermal power plant.

“In case of MCH having arrived in Japan, it will need to be processed for separating hydrogen at such a facility as a refinery,” said Yoshikazu Kobayashi, senior economist at the Institute of Energy Economics, Japan’s planning & administration unit.

“However, it has big enough potential for getting used for power generation at the industrial complex or as an industrial fuel,” Kobayashi said.

Ammonia, meanwhile, has the benefit of being used as a fuel directly, using existing infrastructure in Japan, he added.

COST ISSUES

While Japan’s expected start of liquefied hydrogen transport from Australia will help in expanding its development of a supply chain, lowering cost is a common issue for various hydrogen production and supply options today, Kobayashi said.

Under its basic hydrogen strategy, Japan aims to procure 300,000 mt/year of hydrogen, amounting to 1 GW of power generation capacity, and reduce the cost of hydrogen to Yen 30/normal cubic meters by around 2030.

Japan’s current hydrogen procurement cost estimates stand at around Yen 170/normal cu m based on current technologies, according to the latest estimate released by METI Dec. 21, which is aiming to bring that down in stages to Yen 20/normal cu m by 2050.

METI also noted Japan’s current 100% hydrogen power generation costs are estimated at Yen 97.3/kWh and Yen 20.9/kWh for 10% blending of hydrogen with regasified LNG for power output.

Platts assessed the price of hydrogen alkaline electrolysis at $14.02/kg, hydrogen Proton Exchange Membrane (PEM) electrolysis at $16.26/kg, and hydrogen Steam Methane Reforming (SMR) without CCS at $3.79/kg on Dec 18, with capital expenditures included for all three production pathways for Japan.

However the transport of hydrogen is not without its challenges.

“Hydrogen imports to Japan of whatever color – be it gray, blue or green [or purple from nuclear power] – are unlikely to achieve cost parity with LNG or coal in Japan for power generation for the foreseeable future, given LNG and coal projected pricing through to 2035,” said Constantine Tsesmelis, director & principal consultant at Protos Consulting International, an independent oil & gas, energy & alternative fuels consultancy based in Perth.

“Shipping gray hydrogen to Japan also doesn’t seem to make any sense. Japan could produce many million tonnes of gray H2 from LNG imports without having to go to the cost of developing a gray H2 supply chain,” Tsesmelis added.