Towards the Hydrogen Economy Future

Hydrogen is a transportable and storable energy vector that can be derived from various energy sources. It has a broad span of industrial applications, ranging from refineries to ammonia and methanol production. Its requirement as a feedstock to chemical and steelmaking processes currently represents a strong use case for hydrogen.

However, as hydrogen is increasingly viewed as an integral component of a decarbonized future energy system, its role is expected to gradually change from that of feedstock into a source of cleaner power. Assuming that scalability of power-to-x energy conversion solutions is attained, hydrogen is favored as an option for storing intermittent renewable electricity.

Hydrogen has become a growing focus of attention internationally as a result of policy momentum built towards the decarbonization of non-electric end-uses and the acknowledgment of constraints related to the technical feasibility and costs of full-fledged electrification within the mid-century time horizon of most net-zero strategies.

The aim of this article is to demonstrate how enabling policies, commercially viable investments, including through synergies with the natural gas sector, and proactive regional and international cooperation can kick-start hydrogen economies in Europe, Australia and the Asia Pacific.

EUROPE

Under its Green Deal roadmap and Climate Law, the EU-27 aim to have established an economy with net-zero greenhouse gas (GHG) emissions by 2050. Affordability and security of supply reside at the core of this effort to the benefit of EU energy consumers. Large-scale deployment of renewable energy, energy efficiency improvements and electrification are all steps prioritized to the carbon-neutrality end. Hydrogen is considered as a versatile and progressively cleaner complement to these steps, particularly for hard-to-abate sectors, like industry and transport.

The EU presently produces and uses about 10 million tons per year (mt/a) of primarily fossil-based hydrogen. Renewable electricity (RE) -sourced hydrogen (aka green hydrogen) is promoted as the main transition fuel under the European Commission’s Hydrogen Strategy, while natural gas (NG) -sourced hydrogen with carbon capture and storage (CCS) or pyrolysis (aka blue and turquoise hydrogen) are identified as bridging technologies until upscaling to electrolyzers from the MW to the GW level is achieved.

According to the EU Joint Research Center, the EU has around 1 GW of installed capacity of electrolyzers. Individual electrolyzers currently produce at small-scale level (<1 MW), while larger-scale demonstration projects of up to 10 MW are under development, as per the Hydrogen Roadmap Europe report of the Fuel Cells and Hydrogen Joint Undertaking. The Strategy calls for the manufacturing of electrolyzers of up to 100 MW. This ties in with its three-phase expansion vision regarding: 1) the building of 6 GW (1 mt/a) of electrolysis capacity for use mainly in the chemical industry (2020-2024), 2) the subsequent increase of these capacities to 40 GW (10 mt/a) for additional uses in the steel industry and transport and for the use of RE-sourced hydrogen as long-term storage (2025-2030), 3) the eventual penetration of hydrogen across all hard-to-decarbonize sectors (2030-2050).

Economic prospects

The competitiveness of the different hydrogen technologies will depend on the ultimate size of the domestic European market and the penetration of hydrogen at the sectoral level (e.g., transportation, buildings, power generation etc.) Based on the analysis recently presented by the European Hydrogen Backbone initiative, hydrogen demand in the EU and the UK could reach as much as 2,300 terawatt hours (TWh) by 2050, corresponding to 20-25% of their final energy consumption by the same year.

Despite the wide technological spectrum, the end-goal is to trade a liquid (and preferably euro-denominated) commodity with multiple applications. For instance, development of RE-sourced hydrogen could benefit from economies of scale resulting from industrial-scale hydrogen production from steam methane reforming with CCS. NG-sourced hydrogen may help stimulate demand to be later satisfied by RE-sourced hydrogen. Technology diversity ensures a cost-effective transition and mitigates the risk of failing to meet the net-zero pledge.

Investing close to high-demand spots, including steel plants, chemical complexes and refineries, would enable optimized use of electrolyzers. Europe’s legacy gas infrastructures (e.g., pipelines) could be retrofitted and subsequently repurposed for regional cross-border trade of RE-sourced hydrogen, accompanied by a parallel network of refueling stations supporting the spread of hydrogen fuel-cell vehicles. Given that, before transitioning to dedicated hydrogen pipelines (repurposing), hydrogen will be blended into the natural gas stream up to a technically sound threshold (retrofitting), emphasis should be placed on adaptations of contract prices and price formulae and on force majeure and shipping clauses concerning imported blends.

High liquefaction costs render RE-sourced hydrogen shipping more expensive than pipeline transport, limiting that option to long-distance external suppliers. Australia serves as a notable example in this regard, as shown by RWE’s intention to book capacity at the proposed Brunsbüttel LNG terminal for future import of Australian RE-sourced hydrogen via Germany’s North Sea coast, as well as by Australia’s collaboration with Europe towards cost reductions of CCS through the Carbon Sequestration Leadership Forum.

As for production, Mediterranean Member-States and non-Members, who could possibly export hydrogen volumes to the EU in line with Hydrogen Europe’s proposed 2x40GW split, are endowed with significant solar and wind potential, putting downward pressure on indigenous RE-sourced H2 costs. Offshore wind generation could help ramp up Northwestern Europe’s electrolysis capacity, while the decarbonization of domestic industrial hubs is a boon to the viability and cost-effectiveness of production through unabated gas reforming with CCS, according to the IEA’s Vision towards 2030.

Technological progress, the overall degree of investment and the costs of renewable electricity, raw materials and existing infrastructure upgrades will eventually act as important determinants of the medium- and long-term price of hydrogen in Europe.

Policy support

The Commission’s ‘Power Up’ initiative guides Member-States towards the use of their recovery funding for investment in more renewables, including RE-sourced hydrogen. The European Clean Hydrogen Alliance, gathering stakeholders from the solar, wind, gas, chemical, heating and transport sectors, sets an investment agenda based on the emissions thresholds contained in the EU’s sustainable finance taxonomy, among other standards.

Revision of the Gas Regulation and Gas Directive, in the context of the Hydrogen and Gas Market Decarbonization Package due in late 2021, may serve the establishment of the basic future hydrogen market rules, in order for the EU to safeguard sector integration and avoid the time-consuming creation of a whole separate silo of dedicated hydrogen rules. Such integration of the hydrogen and gas regulation would also help address market fragmentation and problems at cross-border connection points, assuming that a substantial part of hydrogen infrastructure will be repurposed gas infrastructure. A robust regulatory framework will accelerate investments facilitating the uptake of hydrogen. However, due to the de-centralized upstream sector in hydrogen, largely ruling out supply security concerns, and the overall scope of energy system integration, each of the principles of the existing framework will have to be tailored to the particularities of this newly emergent market.

For an established supply and demand market structure to be developed and serviced, levelling costs via tenders for carbon contracts for difference (CCfDs) constitutes a downstream suggestion broached in the Commission’s New Industrial Strategy in relation to the revision of the EU Emissions Trading System (ETS) Directive. In analogy to feed-in premia or tariffs designed to attract renewable investments, CCfDs ensure a minimum CO2 price and therefore incentivize long-term low-carbon hydrogen investments, while hedging against the hiking of CO2 costs in the ETS

According to the Commission’s proposal for the revision of the ETS, released as part of the “Fit for 55” Package, CCfDs are associated with the need to increase the size and extend the scope of the Innovation Fund (Recital 35). Furthermore, Annex 9 of the Commission Staff Working Document accompanying the same proposal points to the relevance of free allocations for installations producing RE-sourced hydrogen and ammonia. Meanwhile, the need to ensure a tax treatment of hydrogen and its applications that reflects their GHG reduction potential and encourages their widespread penetration is overall recognized by the Commission’s proposal for the revision of the Energy Tax Directive, another element of the “Fit for 55”.

Finally, certification serves as evidence of the carbon content of hydrogen and is intended to allow customers to make informed decisions. The Commission’s proposal for a revised Renewable Energy Directive, another legislative update in the “Fit for 55”, includes a 50% binding target for renewable fuels of non-biological origin, such as RE-sourced hydrogen, in industry (Article 22a). It also amends Article 19.2 requiring Member-States to ensure that a guarantee of origin (GOO) “is issued in response to a request from a producer of energy from renewable sources”, removing their right to withhold allocation to producers that receive financial support. In the same context, the well-meant but impractical additionality criterion, mandating RE-sourced hydrogen production from dedicated renewable energy capacity, is thought of as a barrier to the development of a European hydrogen market. A similar system of GOOs may be extended to low-carbon gases under the review of the gas legislation.

AUSTRALIA AND THE ASIA PACIFIC

Australia, which was the world’s largest LNG exporter in 2020, plans to be a major hydrogen player as well. To guide the way, a National Hydrogen Strategy was introduced in 2020. Apart from domestic opportunities, demand for Australian hydrogen is expected from key trade partners like China, Japan, South Korea and Southeast Asia. Geographically, Australia is in an ideal position to be an exporter of hydrogen to Asia, the region that will be responsible for most of the world’s energy consumption growth in the future. Japan in particular plans to be a major hydrogen importer, aiming for commercial operations by the 2030s. As part of that effort, Japanese companies are investing directly in Australian hydrogen projects. China has ambitious goals too, including a target of one million fuel cell vehicles and one thousand refueling stations by 2030. This is a reminder that consumers will play an important role in the hydrogen industry by generating the required demand.

The potential synergies between hydrogen and existing natural resource industries are likely to result in the formation of a major hydrogen regional market in the Asia Pacific, with Australia taking the lead role as supplier. However, hydrogen development in this geographically dispersed region will take time and persistence, including the continuity of technological progress and policy support over many decades in both producing and consuming countries.

Economic prospects

Continuous technological learning-by-doing over time, for all types of hydrogen development, will depend on parameters such as capital expenditure, research and development, knowledge spillovers, economies of scale and favorable policies.

Despite their relative high costs today, hydrogen technologies in Australia are advancing and have potential for significant growth in some end-use sectors. The main obstacles for domestic consumption in urban road transportation are lack of refuelling stations and competition from lower cost vehicles, including electric. The most promising opportunities are to be found in the heavy vehicle sector and the extractive industries, particularly mining.  

Notwithstanding domestic consumption, it is the hydrogen export market that is believed to have the greatest potential for Australia. Deliveries are likely to commence this decade, shipped in liquefied form or as ammonia. It is estimated that an Australian hydrogen export industry will generate billions of dollars per year and tens of thousands of jobs over the decades.

Although competition from other suppliers is likely to arise, costs in Australia are competitive, both for green and blue hydrogen. Apart from the advantages provided by abundant inputs like gas, solar and wind, shipping costs generally offer a significant cost advantage to Australia in the Asia Pacific. This means that hydrogen produced in Australia and transported to Asia may be less expensive overall than domestic development in Asian countries. Australia can further leverage the experience, infrastructure and international connections associated with its gas export industry. Lessons will undoubtedly be taken from the planning and execution of LNG projects, where much has been learned about improving productivity and reducing costs – following the delays and cost blowouts experienced with several projects over the past decade.

The present-day cost of green hydrogen production in Australia is estimated at some US$3 to $4 per kilogram, which is approximately $25 to $35 per gigajoule – many times higher than natural gas and coal prices in the country, or in Asia. Clearly, improved technology and policy incentives are necessary to drive down costs. The most critical factor for the cost of green hydrogen is the price of the electricity, from renewables (estimated to account for around two-thirds of the total cost), used in the electrolysis process.

Cost estimates for gas-based blue hydrogen production in Australia, including CCS, are some US$1.50 to $2 per kilogram. On average, CCS represents around $0.50/kg of the total cost. Another important driver is the price of natural gas, which is currently estimated to account for approximately half of the production cost. However, it must be highlighted that gas prices vary around the country and have experienced a fair amount of fluctuation over the past decade

Considering the economics, blue hydrogen is thought to have greater potential in the coming decade. Still, green hydrogen is experiencing speedy cost declines –some research studies indicate costs could decline by half within a decade. The Australian Government is optimistic too. In its Low Emissions Technology Statement of 2020, the Department of Industry, Science, Energy and Resources set a goal of reducing RE-sourced hydrogen costs to under $2 Australian dollars (~US$1.50) by 2030.

Policy support

Policymakers in Australia are placing additional importance on hydrogen in the wake of the COVID-19 pandemic, with funding provided to dozens of projects. For example, the Australian Renewable Energy Agency, a government body, awards funding to project proposals submitted by industry. Most states in Australia have their own strategies in place, emphasizing either green, blue, or brown (coal-based with CCS) hydrogen depending on their natural strengths and existing infrastructure. Having a comparative advantage across multiple dimensions should accelerate development; e.g., due to favourable geology or climate in the production of gas, coal or renewables needed for hydrogen production; or geography that lowers transport delivery costs to consumers, whether domestic or overseas.

In its 2021-2022 budget, the Australian Government has committed $1.2 billion (AUD) towards the energy sector’s reduction of emissions. This includes support for the development of green hydrogen, but also for CCS – a prerequisite for blue hydrogen. The creation of hydrogen ‘export hubs’ throughout the nation form a major part of the budget initiative.

In the Asia Pacific, several countries have announced ambitious hydrogen strategies. These will incorporate a combination of policy tools, including standards and regulation, taxes that increase the cost of emissions, and subsidies for the consumption and production of hydrogen.

Similar to the natural gas markets, the pricing mechanisms of hydrogen across different regions will vary. Government policies will also play a role in determining prices. An important determinant of an international hydrogen industry will be trade agreements between nations. Initially, the market structure of hydrogen in the Asia Pacific may be similar to the predominant LNG markets, with longer-term deals made bilaterally between large buyers and sellers (sometimes as government levels). As capital investment in hydrogen advances, shorter-term deliveries and market-based pricing should become more common, as is occurring in gas markets around the world.

CONCLUSIONS

Despite the momentum of recent years, hydrogen is likely to become part of a long-term portfolio approach to decarbonizing the global energy system. Thus, it will not be necessary nor practical for hydrogen to be the sole energy provider in the future, but rather one in a group of sustainable resources that will compete with each other based on technical and economic factors in all the end-use sectors.

Still, hydrogen is increasingly viewed as an integral component of a decarbonized future energy system. This text has outlined how policy initiatives at the national and regional levels, commercially viable investments, including through synergies with the natural gas sector, and proactive regional and international cooperation can help kick-start hydrogen economies in Europe, Australia and the Asia Pacific.

In the EU, industrial applications and sustainable mobility issues related to the envisioned hydrogen economy are expected to be dealt with through policy tools forming part of the “Fit for 55” Package, while the upcoming review of the existing gas legislation will support the formation of an internal hydrogen market and associated infrastructural aspects. The Commission currently prioritizes the expansion of the EU’s electrolysis capacity. However, the ultimate evolvement of local clusters of hydrogen production and consumption into an actual EU-wide network will come down to technological potential and scalability of blue and green hydrogen production in North-western and Southern Europe, including the potential for imports from Eastern Europe and the MENA region, as well as to the costs of renewable electricity, raw materials and existing infrastructure upgrades.

As for Australia and the Asia Pacific, some of the facilitating factors for successful hydrogen development include: a growing desire to accelerate the move away from traditionally important fuels, especially coal; collaborative R&D and policy efforts between Australia and the major energy-consuming nations in Asia to advance technology across the hydrogen supply chain and facilitate trade; and the potential to exploit synergies and learn from established industries like gas and LNG – in terms of technologies, infrastructure, project management, market structures, and policies. Challenges include the political inhibitions in some countries to define particular goals, timeframes or tangible plans for achieving carbon neutrality; technical and commercial barriers related to the size and complexity of the region’s geography; and competition from the abundant, lower-cost fossil fuels and incumbent technologies.

Source:  Natural Gas World – Article written by Roberto F. Aguilera, Energy Economist, Curtin University, Perth, Australia, and Mariana Liakopoulou, Energy Security Research Fellow, NATO Association of Canada.

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