National Hydrogen Strategy Issues Papers

To be environmentally sustainable, a solution must first be economically sustainable.

Further analysis is required to determine the exact scale at which hydrogen production capacity and the supporting storage and distribution infrastructure will deliver cost-competitive hydrogen across specific target markets and applications.

The issue paper describes these uncertainties well, covering the need to meet price and volume targets in terms of off-take for specific end-users such as Japan and South Korea.

To meet the potential future demand from multiple applications and markets, which will likely be more closely coupled, an appropriate combination of CCS and green hydrogen production, storage and distribution infrastructure will be required to ensure a balance between affordability, reliability and emissions intensity.

The COAG Energy Council briefing paper ‘Hydrogen for Australia’s Future’ identifies the need for a transitional approach to bridge the gap between today's use of resources and a low or zero CO2 emission future.

This acknowledges that fulfilling hydrogen production for export volumes via the dedicated renewable hydrogen route is currently more expensive than the CCS hydrogen route.

Compared to renewable hydrogen, CCS hydrogen, established in Victoria’s Latrobe Valley could benefit from existing infrastructure, lower network overhead cost and ability to produce hydrogen at a lower cost.

CCS hydrogen is scalable, capable of supporting export volume targets and domestic applications.

Innovations that can cost-effectively reduce the CO2 intensity of current CCS hydrogen production processes should be supported, especially if the cost of their application is less than the alternative cost of CCS or purchasing CO2 offsets.

In this regard, ECT has developed a unique low temperature, catalytic method for hydrogen production from lignite that may have a lower CO2 footprint than current available methods. Cooperative development with CCS hydrogen project proponents via established R&D programs can accelerate commercialisation.

Successfully commercialised, COHgen could make CCS hydrogen cheaper than current estimates by reducing the cost of production, both in terms of direct production efficiencies and via lower CO2 intensity.

Where lignite-based CCS hydrogen producers select a standard high-CO2 gasification route, instead of COHgen’s low CO2 route, they will still need to pre-dry the lignite. In this case, ECT offers an innovative drying process called Coldry.

Traditional lignite drying such as steam tube drying is high temperature and/or high pressure, requiring high paid energy input and generating CO2.

The Coldry process is a low temperature, low-pressure lignite drying process with a zero-CO2 footprint, positioned to deliver a lower cost solution than alternative drying methods.

Zero direct CO2 emissions from the Coldry drying stage results in lower total CO2 emissions and therefore a lower carbon capture and storage (CCS) requirement and cost.

Successful approaches to support skill shortages may include coordination with the COAG Education Council to prepare a 'Hydrogen Energy Industry Training Needs Analysis' and audit of appropriate courses and places required to support the industry. Consultation with engineering firms, academic institutions and unions can seek to achieve a balance between developing the domestic pool of skills and the need to import foreign workers.

As a specific example, upskilling or reskilling workers in the Latrobe Valley to support the shift from a coal-based electricity industry to a hydrogen production industry should overcome the otherwise negative employment prospects for the region.

The issues paper conveys the learning opportunity around the LNG industry well.

Further analysis is required of the unintended consequence of higher domestic gas prices and the flow on to higher electricity prices as gas is increasingly called upon to firm growing, intermittent wind and solar capacity.

Particular attention should be paid to how policies in adjacent areas, such as gas exploration bans and renewable energy mandates and subsidies impact energy reliability and affordability.

Analysis of the relative cost of supporting infrastructure required to link the source of production to markets is required, including transmission lines, gas pipes, storage and ports.

The answer to this question appears driven by the pull of market initiatives in Japan and South Korea.

The government should seek to deliver policy certainty as a priority, which requires detailed techno-economic analysis of proposed scenarios across the various markets and applications to generate the data required for informed decision making.

Ongoing support for innovation in emissions reductions solutions for non-renewable hydrogen and renewable hydrogen is essential.

However, the government need to support post-production CO2 mitigation solutions such as CCS and pre or in-process innovations that avoid or minimise CO2 emissions.

There is a danger that, in seeking economies of size and scale to support the feasibility of a CCS solution in a place like the Latrobe Valley, incentives will be directed away from ‘brown hydrogen’ innovation that aims to reduce emissions. Currently, the Victorian Government-led CarbonNet project is planning a large scale, multi-billion dollar, CCS capture, distribution and storage network with the aim of handling the current CO2 intensity of generation methods like gasification and steam reformation. This level of investment in CCS at the state level may create a structural bias towards hydrogen generation that has a high emissions profile as there will be an immediate need to maximise the use of this new network to ensure rapid pay-back of the investment.

The Federal Government is well placed to balance this in-built bias by the Victorian State Government by offering a carbon credit system to incentivise brown hydrogen production that has a lower CO2 emissions profile per tonne of Hydrogen produced.

CarbonNet Project has estimated that well-established CCS systems cost less than $30 per tonne of CO2 stored, which could form the basis of a meaningful value signal to underpin investment in low-emissions solutions for brown hydrogen.

Federal Government should also consider providing dispensation to the proposed refund cap under the R&D incentive scheme for R&D directed towards supporting the hydrogen industry. As had been considered for the biotech sector, placing a cap on an industry sector where pre-commercial R&D is necessarily large, inhibits the development of technologies required to reach a scale adequate to overcome the risk of large capital investment items typical of this sector.

Whilst difficult for a country like Australia to not be lead by the higher prices export markets pay for commodities, the risk of negative economic impact that prioritising export market growth over the domestic market is mitigated by the fact the hydrogen market is not currently an important part of Australia’s energy mix and an export-driven growth strategy is unlikely to have the same impact observed in LNG market with regard to the increased domestic price of natural gas.

However, there is still a risk that a higher margin energy commodity may displace other energy commodities through existing infrastructure and networks. Reduced access to established networks and infrastructure may place negative pressure on conventional energy sources as a result of supply shocks due to displacement.

The Government will need to consider preservation of the existing delivery and distribution infrastructure to avoid displacement and commit to the expenditure of new and bespoke infrastructure designed specifically for the hydrogen industry.

Clear policy, with bipartisan support in areas like, R&D tax incentives, carbon credits or offsets, environmental laws governed by the EPA, climate change policy and mine rehabilitation, to name a few, is critical to reducing the sovereign and legislative risks of investing in Australia.

Private sector funds are inadequate in Australia to service such a large and transformative shift in energy supply systems and as such, foreign direct investment must be supported and stimulated.

Emphasis on supporting large scale hydrogen production, refinement and transportation using ‘brown hydrogen’ is likely to provide benefits for smaller scale, green hydrogen as the delivery systems to the market will be financed en masse by ‘brown hydrogen’. The drive for renewable hydrogen attributes “pulled” through the networks and infrastructure by consumer demand are likely to be improved where that same infrastructure has been funded by ‘brown hydrogen’. This is due to the lower costs of delivery, although the capacity of these delivery systems to allow for retail and domestic access will be critical.

Hydrogen will be a commodity. As such it will be price sensitive. Minimising production, storage and distribution cost is the key to competing globally.

Demonstration and evaluation of the technologies available and proposed for production, storage and transport will ensure the industry has access to the most appropriate data to deliver competitive outcomes.

Hydrogen will be a commodity. As such, the price will be highly sensitive to supply and demand. The Australian public, via government, will need to support early industry development to provide the social license for formative industry investment. The return on the successful outcome of this investment will be jobs and broader economic activity that will contribute to government revenues via corporate and income tax.

Any direct tax on hydrogen production should consider available margins and be proportionate to other countries.

Substantial lessons can be learnt from the USA’s development of their unconventional gas industry in the formative days. This had the effect of balancing export and domestic demand to the extent that it reduced the impact of price inflation and supply access on domestic operations and consumption.

The issue papers identify learnings from the LNG industry and the impact of export parity pricing on domestic availability and pricing.

This is a complex economic area and structures need to consider the tension between export and domestic objectives.

Supply chain analysis is required to understand the delivered cost across markets and applications to facilitate focus. For example, it may be that renewable hydrogen produced locally in remote and regional communities is economic compared to energy alternatives such as diesel generators or the transported cost of petrol, whereas it may not be economic in the context of export to Japan or South Korea.

The issues paper suggests positioning our brand as ‘Hydrogen Australia’. This is appropriate considering Japan and South Korea are positioning themselves as ‘customers of choice’ on the demand side, attracting action from several nations, including Australia, eager to capture a slice of their market.

Leveraging our track record as a commodity exporter should present a capable, reliable proposition… a trusted partner and ‘safe pair of hands’.

Centralised planning and approvals, origin certification and regulatory support.

Natural monopolies should be identified, assessed and addressed by the government to avoid duplication and provide equal access to project proponents.

Targeted financial mechanisms to help bridge the gap in the financial markets between nascent and mature technologies and industries.

Training programs to support demand for skilled labour to construct, operate and maintain hydrogen facilities.

Accreditation programs under regulatory requirements.

Energy policy, as it relates to the existing NEM and gas markets, has resulted in electricity and gas price increases in excess of the CPI, indicating fundamental issues with policy settings. Given the cost of primary energy feeds into the cost of hydrogen, energy policy needs to correct the legacy of decisions that have led to high energy costs if Australia is to compete globally.

Bringing supply and demand players together via collaborative approaches such as the Hydrogen Energy Supply Chain (HESC) in Victoria which encourages risk sharing and goes a significant distance to dealing with the ‘chicken and egg’ problem

Existing promotional mechanisms including Austrade should be tasked with promoting ‘Hydrogen Australia’

Australia could incorporate hydrogen industry support and supply under its foreign aid program.

Competitiveness begins by ensuring the cost of production is low enough to deliver a competitive product. Getting this right first provides the margin from which to calculate the scope for tax.

In setting revenue mechanisms, the government should benchmark against other hydrogen exporting countries to maintain international competitiveness.

Total excise or royalty revenue should be applied equitably regardless of the production method to ensure technology-neutrality. Consideration should be given to the fact that the cost of CCS hydrogen will already have included the embedded state lignite (or coal or gas) royalty costs.

We can learn from policy outcomes in the LNG market and the National Electricity Market.

For example, when LNG export projects coincided with declines in Bass Strait production and bans on onshore exploration, the domestic gas market tightened, and price increases exceeded CPI.

Likewise, mandates and subsidies for wind and solar without corresponding value placed on grid reliability has contributed to wholesale electricity price increases above CPI in states with higher penetration of variable renewable electricity generation.

Export markets necessarily provide the volume of offtake to support scale-up of production to commercial levels, with the resultant benefit of economies of scale flowing through to relatively smaller domestic applications. As such, export markets should be given priority, with producers required to meet domestic supply reliability measures as part of their social licence to export.

The report ‘Hydrogen for Australia’s Future’, outlines Japanese and Korean hydrogen import targets for 2030 as 300,000 and 170,000 tonnes per annum respectively, with price guidance from Japan of A$33GJ (A$3.96kg). Total 235,000 tonnes.

The report, ‘Hydrogen for Australia’s Future’ states:

"To supply the potential 2030 export market of 500,000 tonnes would require
more than 30,000 GWh of electricity. To put that in context, Australia’s 2020
Large-scale Renewable Energy Target (LRET) is 33,000 GWh, while the total electrical energy generated in the National Electricity Market (NEM) in 2017 was 197,000 GWh."

Using these figures, scaled to produce 235,000 tonnes, the electricity requirement would be 14,100GWh, which would need ~5.4GW of wind capacity (30% capacity factor) or ~6.4GW of solar capacity (25% capacity factor). This is dedicated capacity, in addition to any wind or solar committed or proposed for grid electricity.

The delivery of the renewable generation capacity and supporting infrastructure is technically possible, however further analysis is required to ascertain the likelihood of achieving the target landed cost, given the identified 10-fold decrease in renewable hydrogen costs required.

Germane to this question is the concept that past cost reductions for wind and solar can maintain a similar trajectory.

This is partly informed by scenarios in other areas of innovation, such as computing. Over the past 6 decades, Moore’s Law has seen the efficiency of how computer chips use energy improve by over a billionfold.

Unfortunately, a similar transformation in how energy is produced or stored isn’t just unlikely; it can’t mirror anything close to Moore’s Law with the physics we know today.

A report by CSIRO for AEMO, ‘Electricity generation technology cost projections, 2017-2050’ suggests wind may decrease in cost by 25% under aggressive climate policy. Large scale solar PV may decrease in cost by 45%. Well short of the 10-fold decrease required.

The timing of a regime to guarantee the origin of Australian-made hydrogen as it relates to CO2 is driven by end user requirements in the context of the promotion and marketing of ‘Hydrogen Australia’.

The scheme should include scope 1 & 2 emissions so long as this is internationally consistent.

Australia should seek to harmonise domestic and international origin certification requirements where possible.

Requiring CCS for fossil fuel-based hydrogen production supports the principle of technology neutrality in the context of CO2 constrained markets.

The issues paper adequately covers the key issues.

Many concerns arise through biased representations from narrow interest groups.

Education and unbiased information should be curated and provided by the government.

We note there are several research groups seeking to develop anodes for direct electrolysis of seawater. If successful, this may negate the need for desalination.

If this takes time or is unsuccessful, renewable hydrogen will need to incorporate the treatment cost, further hampering its economics.

If the desalination or water treatment plant is powered by fossil fuels, then this becomes a 'Scope 2' CO2 emission in the hydrogen supply chain, shifting the certification from zero to low-carbon.

CCS hydrogen is compact and could leverage the existing infrastructure in the Latrobe Valley, minimising land use and community disruption compared to renewable hydrogen alternatives.

The issues paper notes that water use is similar between CCS and renewable hydrogen. Planning for impacts on supply and price is essential regardless of the technology deployed.

Issues arise for renewable hydrogen facilities located in remote areas. Solar resources are located in areas with typically lower water resources. This requires the power to be transmitted to locations with water availability, entailing transmission losses and additional infrastructure spending commitments.

A whole-of-government approach needs to be adopted via a central agency, with clear facilitation capability embedded within the approvals process, from project concept through to commissioning, certification and ongoing monitoring.

Existing hydrogen industry regulations provide an appropriate basis for regulation and education.

Any issues that impact on broader energy affordability or reliability are crucial to both export and domestic objectives.

The models identified in the issues paper are appropriate.

The models identified in the issues paper are appropriate.

Application of existing regulations delivered by existing structures, with the benefit of additional hydrogen-specific expertise, should deliver safe outcomes.

Safety is the number one consideration. Cost is the second. There is no long-term hydrogen opportunity domestically or internationally unless people know it is safe and until we can deliver hydrogen at the right price and on a reliable basis.

It is clear that CCS hydrogen and renewable hydrogen will receive support from sections of the community with different viewpoints. Objective, unbiased education is essential to ensure a technology-neutral approach.

ECT defers to industry experts with regard to gas networks.

ECT defers to industry experts with regard to gas networks.

ECT defers to industry experts with regard to gas networks.

ECT defers to industry experts with regard to gas networks.

ECT defers to industry experts with regard to gas networks.

The issue paper provides a good overview of the challenges and options.

Three distinct opportunities for hydrogen have been highlighted through the consultation process:

1) Export
2) Domestic
3) Grid-firming

Two routes are proposed:

1) Renewable hydrogen (wind & solar plus electrolysis)
2) CCS hydrogen (fossil-fuels plus carbon capture and storage)

These routes present profoundly different primary energy scale challenges.

The Finkel Review recommended a Generator Reliability Obligation which provides that if a “new” variable renewable energy (VRE) generator wishes to connect in a region that is close to the limit of minimum dispatchable capacity, that it must provide an amount of new dispatchable generation capacity from within the same region.

That dispatchable generation capacity cannot come from existing sources.

There are times when the wind is blowing or the sun is shining, and no one needs the electricity. This electricity is generally curtailed and therefore lost. At present this may be as high as 10% of the time.

Directing this ‘spare’ renewable energy to storage, such as batteries, pumped hydro or hydrogen electrolysers would help firm the intermittency of wind and solar, creating dispatchable’ renewable electricity. This is covered in detail in the CSIRO’s National Hydrogen Roadmap.

Unfortunately, according to the National Hydrogen Roadmap, while renewable hydrogen has the lowest electricity input cost (~2c/kWh) when it uses otherwise curtailed wind or solar, the capacity factor of the electrolyser is close to 10%, resulting in an estimated hydrogen cost of ~$26kg due to inefficient plant utilisation.

Renewable hydrogen may have a place as a solution for grid-firming in the context of a broader approach utilising a combination of batteries, pumped hydro and hydrogen. This is outlined in ARENA’s 2018 report; Comparison of Dispatchable Renewable Energy Options and should be considered a direct cost of wind and solar, per the Finkel Review recommendation.

Further analysis is required to confirm the techno-economic feasibility thresholds for renewable hydrogen firming as a result of increased wind and solar penetration.

The scale challenge for the hydrogen industry is not hydrogen production itself but scaling the primary source of energy used to make the hydrogen.

Hydrogen production should not come at the expense of domestic energy affordability or reliability.

Hydrogen-based grid firming should be considered in the context of the broader application of firming options, including batteries and pumped hydro.

Balancing supply and demand will be the challenge. The tension between servicing potentially more profitable export markets compared to domestic electricity markets may result in a similar outcome to the LNG market.

The HESC pilot in Victoria provides a good benchmark, involving a whole of supply chain approach. 

ECT defers to industry experts on this question.

ECT defers to industry experts on this question.

ECT defers to industry experts on this question.

ECT defers to industry experts on this question.

ECT defers to industry experts on this question.

ECT defers to industry experts on this question.

The ability of hydrogen to act as a reductant in primary iron production is well-known. The barrier to adoption has been high cost, relative to the incumbent blast-furnace route.

It is envisaged that green hydrogen will one day deliver CO2-free iron and steel via hydrogen-based methods.

The commercialisation of renewable hydrogen steel making is estimated to be a generation away given the scale and cost challenges.

ECT has developed the ideal transitional solution; HydroMOR. Short for Hydrogen-based Metal Oxide Reduction.

HydroMOR is the only lignite-based iron making process, replacing coking coal and thermal coal with lignite, combining it with iron ore fines or other metal oxide-bearing media via the Coldry process to produce a ‘composite’ pellet. The composite pellet is then fed into the unique HydroMOR furnace where several reactions take place:

• Pyrolysis and gasification of hydrocarbons within the lignite
• Catalytic thermal decomposition of the hydrocarbon gas to liberate hydrogen
• Reduction of iron oxide to iron at less than 900C (relatively low temperature)
• Chemical looping of hydrogen within the process via a water-gas shift reaction (recycling the hydrogen for further reduction of iron oxides)

The result is the in-situ utilisation of hydrogen for iron making and the elimination of the cost needed to independently generate, transport, store and then apply it to iron ore, providing an advantage for regions with suitable lignite and iron ore resources.

Note that this approach is fundamentally more efficient than external production of hydrogen, followed by usage of that hydrogen within a process to reduce the oxide to metal.

Waste to energy or bio-mass to energy is the primary focus for industrial-scale heat generation in the context of tackling emissions intensity and affordability.

Where waste or bio-mass is available and within desired specifications for moisture, energy and ash content, it is more cost-effective than the alternative of natural gas or LPG.

Waste and biomass are considered to be CO2-neutral as it is expected to release greenhouses gases as part of their lifecycle, either via landfill methane emissions or natural decomposition.

To compete, hydrogen would need to deliver lower or equal energy cost than these alternatives in the context of any additional capital upgrades required to allow the boilers to use it in a safe manner.

Given Victoria has the largest number of industrial boiler systems, the Latrobe Valley is a logical location for a CCS hydrogen facility and broader supporting gas network.

A detailed market study is required to answer this question on a national level.

In the context of small to medium scale utility process heating systems (e.g. 4-10MW boiler and hot water systems), conversion to hydrogen consumption would require, at minimum, complete change out of combustion systems to allow safe use of hydrogen as a combustion fuel, or entire replacement of the combustion and boiler systems in the case of existing solid fuel users.

The most sensible trial sites for conversion to hydrogen fuel would be existing natural gas boiler systems, where change-out costs are constrained to fuel combustion systems.

Most existing systems encountered in the segment mentioned above do not have existing facilities or capabilities to handle increased NOx emissions.

Existing hydrogen industry regulations should be applied.

The key to the transition is affordability and reliability.

CCS hydrogen is scalable and more affordable in the near term. Renewable hydrogen is more expensive and, according to current estimates, unlikely to achieve the 10-fold cost reduction required to meet market expectations by 2030 or even 2050.

Government support for CCS hydrogen is essential to bridge the gap between today's use of resources and a zero-emission future.