National Hydrogen Strategy Issues Papers

This question has a simple answer and a nuanced answer. The simple answer is that the more quickly we scale renewable hydrogen production the quicker the cost will come down, and in the longer term we should aim at achieving sufficient scale to replace a significant proportion of Australia’s current coal and natural gas exports in order to future proof our export earnings.

It is highly likely that international efforts to reduce greenhouse gases are going to accelerate, given the science currently emerging. The sustainable development scenario published as part of the World Energy Outlook series shows a decline of 57% in coal demand by 2040, with coal trade falling by 53%, which puts Australia’s coal exports in a highly vulnerable position, so the development of a viable alternative which can continue in a carbon constrained world is important. Rapid scaling of truly renewable hydrogen would accelerate the cost reductions in the area in which Australia has the most natural advantage, namely low-cost renewable electricity, and increase our long-term market share. Potential recipient countries have already set targets for carbon intensity of imports, with zero carbon H2 favoured (Kosturjak, et al. 2019).

Our coal and LNG exports in 2018 were equivalent to 103 MT of hydrogen in terms of energy, and 27 MT of hydrogen in value (based on a hydrogen cost of 3 USD per tonne). At least one international projection for ammonia puts Australia’s potential exports at 350 MT by 2050, equivalent in mass to about 62 MT H2 (Brown, 2018). By contrast, the high scenario hydrogen export forecast for Australia by ACIL Allen (2018) reaches only 3 MT at 2040. Increasing ambition to assume Australia provides 50% of Japan’s and Korea’s hydrogen imports would take this to 7 MT per year by 2040. Replacing the value of our energy exports would require Australian to achieve a significantly larger share of the rest of the world market, which may be plausible in the context of rapid development of renewable hydrogen with consequent cost reductions. Certainly, further detailed analysis seems desirable to quantify the opportunities and risks for Australia.

Domestic uses of hydrogen, such as transport and hydrogen generation, will be small by comparison. The same is true of the renewable power generation, as is the case for the present coal industry where less than 1/5th of production is used domestically (although the scale of renewable power generation required could play an important role in supporting the electricity grid by offering balancing services) . Profitability will be achieved somewhere along the way due to cost reductions driven by global industry scale according to well-known scaling laws (ITP Thermal, 2018).

The nuanced answer accounts for diverse uses for hydrogen which would each have different pathway for profitability. The premium value attached to the renewable product, compared to hydrogen derived from fossil fuels, would have a strong bearing on the relative profitability of each market. For example, ammonia is a presently traded hydrogen product used as a feedstock in the agricultural and chemical industries, and indications from European industries are that there is demand developing for a renewable product.


References:
Brown, T. What drives new investments in low-carbon ammonia production? One million tons per day demand. Ammonia Industry, April 20th 2018

ITP Thermal Pty Ltd (2018) Comparison of dispatchable renewable electricity options: Technologies for an orderly transition.

Kosturjak, A. et al. (2019) Advancing Hydrogen: learning from 19 plans to advance hydrogen from across the globe. P.37

Ensuring that renewable hydrogen is developed in such a way as to provide balancing services for our electricity system avoids developing an entire infrastructure for balancing that could be provided as part of our export industry. It could also avoid the situation where export is competing with domestic supply, as has occurred in the LNG industry, and lead instead to a much healthier complementary relationship between domestic and export industries.

Identifying those markets where there may be a near term demand for renewable hydrogen, such as chemical feedstocks, and projecting our scale up and consequent cost reduction could accelerate the process and bring forward contracts to underwrite industry development. Underwriting the supply of renewable hydrogen for our domestic chemical industry, effectively to create demand, could bridge some of the gap towards sufficient scale up to reduce the cost gaps.

Similarly, recognising emerging international demand for renewable ammonia, underwriting the early stages of production would be a wise strategy to secure markets, technical capability, and a well-prepared workforce. Yara and Engie are collaborating to pilot a modest-scale adaptation of their existing operations in the Pilbara. These produce an average 840,000 million tonnes of ammonia per year for domestic and export markets. The pilot plant will use a 100 MW solar array to produce hydrogen by a 50 – 60 MW electrolysis plant, which will be combined with atmospheric nitrogen to produce 29,000 tonnes of green ammonia per year . Engie brings formidable international experience and vision, while Yara is a long-established Australian industry, with an appetite to repurpose its infrastructure over time. There are similar opportunities on the east coast.

The high export scenario described in the ACIL Allen report estimated the renewable generation requirement to be 200 TWh, which would involve at least a 12-fold increase in wind and solar generation compared to current levels. Realising a renewable hydrogen industry comparable to current energy exports would need more like a 200-fold increase in wind and solar generation. This will need a huge industry scale up and considerable effort on skills and training.

There are currently almost no reliable data on employment or skills requirements in the Australian renewables sector, and very little detailed information available internationally. We suggest that this data should be collected as a matter of urgency, including detailed projections of skills requirements for the low, medium and high growth scenarios.

This work is integral to achieving a Just Transition for the workforce currently reliant on fossil fuel exports. Skills mapping should be undertaken to identify appropriate opportunities for retraining, in consultation with the affected communities. The opportunities for locating infrastructure in areas likely to be impacted by the decline of fossil fuel industries should be identified at this stage, and enacted where possible.
The detailed workforce mapping for wind and solar has been commenced by the University of Technology Sydney for the Clean Energy Council. This should be extended and integrated into skills and infrastructure planning.

Australia has always had to find a balance between fostering our own industry leadership and leaning in on international know-how and investment. We have achieved a position of leadership in a number of energy subsectors, including hybrid power systems, mining automation, rooftop solar generation, and LNG production. As a middle-ranking economy with a small population, we need to be selective when choosing areas where we can aspire to be global leaders.

Large-scale renewable hydrogen production is an area where Australia could excel globally and establish an industry with a significant local supply chain. Particularly standing to benefit are Australia’s regional communities. To maximise this benefit it is important to achieve scale at a pace that allows local supply chains to develop in a sustainable way. FIFO workforces have been used to build mining infrastructure rapidly during the growth of that industry, however, this model has created considerable problems in local communities that are seeking economic diversification but are bypassed when rapid scale up is required. They are also expensive.

Planning ahead and investing in the early growth stage of the green hydrogen industry could help regional communities by establishing permanent workforces with the necessary skills in renewable energy generation, transmission, storage, conversion, and export.

Australia’s natural advantage lies in our renewable resources, combined with our political stability and reliability as a trading partner. We need to develop and accelerate the renewable pathway, in combination with renewable certification that emphasises this advantage, and do this with specific reference to the long term – that is, the zero carbon targets for 2050.

Developing renewable energy supplies for hydrogen production in a way that provides equity to Traditional Owners will also go a long way to achieving the community social responsibility goals of both Australian and international companies. A number of countries have achieved higher economic participation of indigenous peoples than Australia, and would be encouraged to see progress towards this goal. With our neighbour Indonesia, particularly, there are strong historical connections between our indigenous peoples, and development that provides equity to Traditional Owners could substantially lift the potential for Indonesian investment in Australian projects .

The greatest boost to cost competitiveness is scale, and we should put all our efforts into scaling renewable hydrogen. The CCS options are stop-gaps, and highly expensive ones at that, and may actually hinder the cost-competitiveness of renewable hydrogen by slowing down the deployment of electrolysers. Certainly, government effort and spending should be entirely focussed on the long term strategic advantage to be gained from renewable hydrogen, and the associated tasks such as certification, work force planning, regulation, licensing, infrastructure integration.

It is not unusual for governments to pick a suite of technologies and invest public money to develop competitive advantage in a strategic industry. As several countries declare a “climate emergency” and a larger number begin to experience the effects of one, it does not require a great leap of faith to see Australia becoming a leading global supplier of green hydrogen products to aid rapid decarbonisation. Our plentiful renewable energy sources, long coastline, port infrastructure, and access to key markets are a set of natural and strategic advantages that urge government priority and action.

Develop excellent guarantee of origin standards in partnership with key trading nations. Note that these should be include both stringent measurement of carbon and social responsibility, in order to make clear our natural advantages.

This requires multiple approaches, including ensuring that renewable generation for export underwrites our domestic supply, consideration of a sovereign wealth fund, and ensuring the inclusion of Traditional Owners in the economic opportunities created by hydrogen developments.

Ensure that the scale of renewable generation required for hydrogen exports keeps electricity prices low for consumers by system integration. This applies both to the cost reductions to be expected to such large scale development of wind and solar, and to the cost reductions by shared infrastructure for domestic and export electricity supply. This could be achieved in a number of ways: linking licenses with priority maintenance of domestic electricity supply (noting the precedent set with coal mine development, where supply to domestic generators was part of license conditions), or linking development support to such priority.

Australia should consider setting up a sovereign wealth fund along the Norwegian model for ensuring that favourable times provide lasting benefits to citizens.

There is no necessity to find a balance, which can be driven by their relative demand and our diligence in seeking markets. Export and domestic demand can co-exist helpfully and the economics of one can be helpful to the other, for example by creating multiple uses of hydrogen production and storage infrastructure, and creating multiple off-takes to protect the industry from variations in either export or domestic demand. In the early years, incentivised domestic demand can be used to create a market, in order to scale the industry up and drive the price down ready for the export market. In later years the renewable generation sufficient to produce hydrogen for export should keep domestic electricity prices low.

Arguably, there is no pressing reason to have a domestic hydrogen industry in Australian although (along with transport electrification) it would be useful in reducing our dependence on imported liquid fuels. On the other hand, the decline of our coal and gas markets will create a very pressing reason to have a hydrogen export industry. This suggests that the appropriate balance would lean in favour of the export industry. As has been noted elsewhere, this is already true of our coal industry, and so is not an unusual situation in the Australian energy sector.

According to the ACIL Allen (2018) medium scenario estimates, the hydrogen demand in Japan and Korea in 2030 will be 211.5 PJ and 87.4 PJ respectively, with these figures at 463.3 PJ and 187.5 PJ in the high scenario. ACIL Allen expect the domestic supply to be 15% in both countries and that Australian imports will provide 21% and 11% of demand respectively. To assume 50% of imports, or 43% of demand, will be from Australia is a significant increase from these estimates of market share and assumes a more vigorous and successful trading strategy.

In terms of the infrastructure requirements in Australia achieving a scale up to 50% of demand is not unreasonable for either the medium or the high scenario. Approximately 2.3 million tonnes of hydrogen would need to be produced and transported to provide 50% of imports in the high demand scenario for Japan and Korea combined. This would require 130 GWh of electricity per year which compares to over 27 GWh of wind and solar energy generated in Australia in 2018 (CEC, 2019). This is not an unreasonable ambition for scaling up over a decade focussed on advancing our green hydrogen export industry. Shipping the 2.3 million tonnes of product per year is not difficult, for example the Yara Pilbara facility produces 840,000 tonnes of ammonia per year which requires 32-34 shipments. For shipping the hydrogen will need to be compressed and chilled; or if shipped as ammonia then 13 million tonnes will be required per year.

Guarantees of origin should be in place within the next 4-5 years, so that industry development can occur in the context of certification, and trading partners can have both confidence and knowledge of the way that hydrogen products can and will be differentiated. Certification schemes should be sufficiently progressed so that it can be built into both contracts and an MOUs that are developed.

There should be a single scheme to meet domestic and international requirements to avoid unnecessary compliance and reporting costs.

The minimum requirement for certification is that there is detailed, robust and transparent information on carbon emissions associated with production, conversion, and transport.

Central to certification is the need for easy identification of zero carbon hydrogen and hydrogen products. As countries increasingly move to zero emission targets, confidence in certification and the ability to source zero carbon products is likely to become a material factor in determining trading partners (remembering that the key driver for the H2 market development is decarbonisation).

In addition, there should be consideration of additional certification on water use and other issues such as equity to Traditional Owners. Research should be undertaken on whether there is a consumer concern for these additional factors, which could be provided as secondary information (such as a separate label) – noting that this information is not available for other energy supplies and may not be so relevant for trading partners. However, any aspects to be certified should be done so as part of the same process, and the certification handled by the same body.

The guarantee of origin is important so it can be built into trade agreements, and fundamentally protects Australia’s competitive advantage (high availability of cheap renewable power).

The threshold for any certification should be set at good practice SMR plus CCS (that is, at 1 kg CO2-e/kg hydrogen), however the certification must further distinguish between low carbon and green.

The future market for H2 and the expectation for Australia to be a major exporter arises from the need to decarbonise, and particularly for countries such as Japan (without significant energy resources) to be able to import low and eventually zero carbon energy. H2 from current practice (SMR without CCS) has no long-term value, other than for transition, and inclusion of H2 from these sources will only make the transition more opaque. If supply chains are mixed, the seller can presumably deliver shipments with certification attached to a percentage only of the H2, which in effect would allow purchasers to calculate the emissions for the entire shipment.

Certification and standards are best retained under the control of governments, to allow a consultation less subject to vested interest, and to ensure that there is international collaboration with other standards bodies, and to give public confidence.

Integration may bring the lowest overall system costs if the benefits for bringing forward H2 electrolysis and the avoidance of unnecessary electricity storage costs are considered. However, this is a system question, and the optimum course needs to be considered in an integrated fashion, as considering costs of H2 production alone (particularly short term) will not take account of electricity system benefits.

The viewpoint of the electricity industry is that integration is the best option, because it is an extension of existing business models, and it provides options to support flexibility and reliability in either direction. That is, interconnection with the grid allows variability of demand to be managed across a wider portfolio of loads and enables contingency options and services that would not be available in separated systems. For example, should an HVDC connection be built to connect large-scale electrolysis on the coast with renewable energy developments inland, the HVDC converter station would appear to the grid as a highly flexible power station well suited to managing load and generation variability. Conversely, should such a link experience an outage, interconnection with the grid would mitigate the impact on the electrolysis facility and hydrogen exports.

Integrating with the regulatory framework of the existing grid would also ensure that a consistent project assessment framework is applied to transmission projects associated with hydrogen production. This would tend to make such investments more efficient from a societal perspective. It is admittedly not a perfect system, but it would be an improvement on unregulated private assets that could compete with public or regulated assets.

This question requires some work to answer thoughtfully. It is appropriate to undertake research to compare integrated (connected) or separate development, in particular:

• Economic modelling of electricity system costs with and without electrolysers playing a significant role in balancing, i.e. performing the storage task that would otherwise be required,

• Economic modelling of H2 costs over time with separated / connected development, including the ability to scale and serve both domestic and international markets at different stages of development,

• Qualitative comparison of flexibility in each pathway to serve different markets – e.g. domestic, international, sectoral, and to respond to world acceleration of demand,

• Market design including the potential for co-optimised hydrogen and electricity markets and mechanisms to ensure both electricity and hydrogen are available at competitive prices for domestic purposes.

Hydrogen fuel cells and hydrogen-fuelled gas turbines can support electricity systems in the same way as batteries and conventional gas turbines, and are incentivised by the same market signals – there is no need for additional ones specific to hydrogen. Long-duration (e.g. seasonal) energy storage can also be provided by hydrogen and the present market framework does not necessarily incentivise the most efficient balance of energy storage technologies and durations for a reliable electricity supply. This issue is not specific to hydrogen and is a symptom of the emergence of battery energy storage, particularly, as an economically viable option and of the increasing penetration of variable renewable generation in Australian electricity systems.

Several industries with major Australian operations (e.g. Woodside, Shell, and Yara) have forward-thinking strategies to develop renewable hydrogen production. They should be given every encouragement and support because they have the balance sheets to develop test facilities at a scale compatible with industrial processes, and they can test the value of renewable hydrogen in a number of existing international markets.

Demonstrations led by new Australian companies may (as is the case with the H2U project in Port Lincoln) have a focus on domestic markets as well as export potential. They are equally important and will develop Australia’s own know-how and technology base to help secure our market participation and share.

In relation to renewable electricity supply, for all such demonstrations, working groups should be facilitated to include existing network operators, project developers, and regulators so that questions of integration with hydrogen production can be discussed.

It may be appropriate to make development support for hydrogen facilities prioritise grid integration and provision of appropriate services. Development support is likely to play a significant role during early stages of the hydrogen industry, so this may allow a window for gaining experience and undertaking research on the optimal system design in order to determine what any regulatory reform is required.