National Hydrogen Strategy Issues Papers

For the production of renewable hydrogen, a key driver of cost ($/kg H 2 ) is the capital cost of the electrolyser. Therefore, driving down electrolyser capital costs is critical for achieving commerciality in the use of renewable hydrogen. Technologies such as electrolysers typically benefit from the learning effect, where increases in the cumulative capacity deployed drives a reduction in capital cost.

Another key cost driver is the energy input cost. For renewable hydrogen, this is generally considered to come from large-scale solar PV and wind. These technologies also exhibit declining costs through increased scale. As such, increasing activity and scale in the hydrogen production supply chain will require increasing amounts of renewable energy generation which will drive these costs down and create a positive feedback loop.

Applications that can support a higher hydrogen cost (e.g. transport) will become competitive at smaller scale (i.e. cumulative deployed electrolyser capacity) than applications requiring a lower cost (e.g. residential heat).

Hydrogen projects are likely to require government support until the cost of hydrogen is sufficiently low for projects in a given application to proceed on a commercial basis.

The total amount of government funding required to commercialise Australia’s hydrogen sector can be minimised by focussing initially on small-scale demonstrations (e.g. up to 10 MW electrolysers), and on applications that are commercial with higher hydrogen costs (e.g. transport and remote area power systems (RAPS)). Progress achieved in these demonstrations will bring down the cost of hydrogen production, reducing the cost of government support for the next scale of demonstration and deployment (say 10-40 MW projects).

Achieving scale up also requires matching production with demand, so demonstrations and pre-commercial deployment projects at the 10-40 MW scale need to be in applications with sufficient demand, for instance RAPS, ammonia production, heavy transport and gas grid injection. Demonstration and pre-commercial deployment at this scale will then help bring down costs for the next scale of deployment (e.g. 100+ MW projects) and projects that need a lower cost of hydrogen, e.g. hydrogen export.

Existing infrastructure in the following areas has been discussed between industry and ARENA:

- Ammonia producers replacing natural gas inputs
- Gas network providers (ATCO and Jemena have been supported with demonstration projects) investigating blending into existing natural gas pipelines.

Jemena has also noted that projects that make use of ‘sector coupling’, having multiple revenue streams and therefore spreading the risk of demand and price variability, will also be a key strategy for scale-up.

The higher cost of small-scale production can be offset (in part) by focussing on high-value applications. Remote Area Power Systems currently require transportation of significant quantities of diesel across Australia and operate with LCOEs of up to $400-500/MWh. Establishing small hydrogen projects in these areas can assist in overcoming scale-up development issues. Third party or joint venture ownership of connecting infrastructure (such as pipelines and distribution hubs) could also help to minimise the duplication of assets issue as seen in onshore gas development.

Alternatively, it is noted that the Asian Renewable Energy Hub is being developed at significant scale (up to 15 GW of wind and solar generation—3 GW of generation for Pilbara energy users and up to 12 GW of generation for green hydrogen production). By oversizing the solar and wind generation in a highly prospective area, the cost of hydrogen can benefit from making use of ‘spilled electricity’ and deployments at this scale can help reduce the $/MW capital cost.

Another factor in the cost of hydrogen production is the capacity factor of the hydrogen production process. This refers to the percentage of available time in the day and night that a plant operates. As a general rule, the greater the capacity factor (i.e., the closer to 100%) the lower the cost of hydrogen produced. A grid-connected hydrogen production plant should be able to operate at a higher capacity factor than a plant powered by off-grid solar and/or wind.

The ability for hydrogen production to utilise sector coupling (as highlighted in the answer to question 2 above) would be one option to implement the early stages of workforce transitions and upskilling. To be able to do this effectively across sectors will require a well planned approach not dissimilar to the programs currently in use for the integration of renewable energy technologies at mine sites across Australia. A notable example is the ARENA-funded feasibility study for the Kidston Solar and Pumped Hydro project, which is expected to provide opportunities to the local community through upskilling and transitioning. The ARENA-supported Nyngan Solar Plant project also produced a publicly available knowledge sharing report, outlining the lessons learnt for finding labour for remote sites.

Attention should also be directed to building workforce capacity in early hydrogen projects (2019-2021).

Some relevant lessons from ARENA’s large-scale solar experience include:
- Foreign exchange risk on the price of imported hardware can drastically influence the capital cost of the project and needs to be accounted for upfront.
- Storage and transport of a large amount of inventory at scale adds additional cost and logistical complexities.
- Remote project sites typically don’t have quality roads that can support large trucks driving additional cost and time spent to access sites.

Based on indications from industry and prospective applicants, ARENA expects an indicative timeframe for scale-up is: demonstration projects of up to 10 MW electrolysers to be developed until -2020; pre-commercial projects of -10-40 MW in -2020-2022 and early commercial scale projects of -100-300 MW in -2022-2025.

Grant funding will be required to support demonstration projects and pre-commercial deployment projects and support the scale-up of the industry to realise the renewable hydrogen export opportunity. Based on ARENA’s experience with supporting renewable energy industry development, we expect the required level of support could be in the order of $200-500 million. This could be provided through:
- programs such as those administered by ARENA2
- the creation of a hydrogen-specific fund
- additional funding from State Governments
- continued support for R&D to help lower hydrogen supply chain costs in the medium and long term.

Establishing long term policy frameworks, and reducing the costs and timeframe for private sector investment makes the environment more attractive. Effective methods for leveraging private sector finance can be borrowed from principles used by ARENA:

- setting funding priorities for maximum impact that are revised as required in response to changing market conditions or technological developments
- being technology neutral in setting investment priorities
- having a diverse investment portfolio
- having a commercial focus where each project supported has a credible pathway to becoming viable
- seeking to support impact in the sector rather than just discrete projects, through a portfolio of complementary projects
- carefully sizing the grant to enable projects to proceed while minimising the Government contribution.

Support from Government should decrease as the level of risk in each hydrogen sub-sector decreases. Support should also become more targeted over time, as it becomes clearer which technologies and applications are unlikely to succeed, or do not require continued support to grow.

ARENA’s experience indicates first-of-a-kind projects and innovative technology developments are likely to require up to 50% in Government grants, but this will decrease as sectors mature and allow for support to shift to concessional finance as they reach increasing levels of commercial readiness. Education of the investment community can help them become comfortable with the technology and the commercial risks and opportunities (as has been observed for example in ARENA’s support for energy from waste).

Innovative business models can be tested using small-scale projects that are supported by Government. In addition, any feasibility activities should include the support of industry partners who have the ability to fund the deployment of projects to ensure projects have a commercial pathway to commercial investment.

Collaboration and co-funding in RD&D with local and international upstream and downstream industry stakeholders could help Australia capture a wider share of the hydrogen value chain (including in the knowledge sectors).

Many of the technology, regulatory, policy and supply chain components required to support the development of a large-scale hydrogen export industry are yet to be settled. ARENA has observed significant interest by industry and research communities in solution development and sees a continuing role for Government support for R&D, feasibility studies and early-stage demonstrations that can reduce costs (through new technology applications and learning) and de-risk projects for prospective investors. ARENA also expects that a strong national policy vision from government, supported by appropriate policy settings and targets, will help attract global and local investment in R&D and project deployment. Given that the global demand will be for zero or very low-carbon hydrogen, it is important that government policy, and the industry’s development effort, is clearly linked to the broader adoption of renewable energy across the Australian economy. This will provide confidence from prospective customers and investors in the sustainability of Australia’s hydrogen economy.

By 2030, Japan’s demand for hydrogen is estimated to be 1.76 million tonnes and Korea’s demand 0.73 million tonnes (ACIL Allen, medium scenario). Assuming that neither country will produce a significant amount of hydrogen domestically, 50% of hydrogen imports is 1.25 million tonnes, or around 150 PJ. To produce this amount of hydrogen using electrolysis would require 82,000 GWh. Considering that renewable electricity generation increased by 3,838 GWh in 2017-18 (Australian Energy Statistics), it is certainly feasible that dedicated renewable energy generation could be deployed over the next 10 years in order to meet 50% of Japan and Korea’s hydrogen imports. The challenge, however, will be in coordinating investment in renewable power production, hydrogen production and shipping in parallel to the commercial offtake arrangements with buyers to meet this timeframe. This can be assisted by substantial early investment in R&D and demonstrations that can build confidence for investors in project risks and pricing.

Another consideration is that one of the drivers for Japan and Korea in developing a hydrogen economy, is to increase energy security by reducing reliance on imported fossil fuels. Having a high supply of hydrogen from a single source may not be acceptable given this aim. Despite this, 65% of coal imports by Japan came from Australia in 2015, indicating that 50% of hydrogen imports from Australia could be accepted.

ARENA’s experience working with energy project developers across Australia indicates that community support is enhanced by early and regular consultation and benefits sharing that encourages and empowers community participation. Many projects in regional areas benefit from specific strategies to engage the local indigenous community and ensure the community is enfranchised through the decisions made by the project proponent. An example of this community engagement approach can be seen in the ARENA funded project SETuP which employed “job-ready” locals with transferable skills. Lessons learnt from this project include recognising the importance of community engagement, maximising opportunities for local enterprises and facilitating local employment.

ARENA has contributed funding to the development of industry codes for renewable energy developers. ARENA supported the extension of National Wind Farm Commissioner mandate to large-scale solar farms and energy storage facilities. Noting the likelihood of hydrogen production being co-located with wind and solar farms and storage, ARENA considers the Commissioner would be well placed to translate best practices for industry and government to the planning and operation of hydrogen projects.

The ARENA-supported Moree Solar Farm project had a number of lessons learnt that were published as part of their public final report:

- Progressive communities: Select localities supportive of development determined through early engagement with local government and community.
- Engage early and openly: Transparency is respected.
- Effective community engagement: Listen rather than promote and engage with issues that are important to the community rather than what the project owner thinks should be important to the community.
- Fit-for-purpose consultation: Don’t over consult, but provide regular status updates to ensure that misconceptions regarding the project do not emerge.

These lessons have been echoed in ARENA’s other large scale solar projects, which have experienced overwhelmingly positive community consultation.

ARENA has supported the $3.53m ATCO hydrogen microgrid project, which tests the use of 100% hydrogen on a small scale using a modular home, with excess hydrogen blended into the natural gas network. The project recently began operations and will be essential in determining lessons for scale-up to a larger number of houses. 100% hydrogen grids will require continued Government support to drive scale-up, facilitate knowledge sharing throughout the sector, and ensure that any customers involved in trials are not exposed to increases in energy prices because of participation.

The next test project of a 100% hydrogen grid will likely include only a handful of houses, with scale-up to service a region still some way off. The location of such a trial will need to consider the summer and winter peak loads and current natural gas use, with the most benefit being in areas where natural gas is used for winter heating. The use of renewable hydrogen could enable a higher renewable energy penetration without the need for electrification. Consideration would also need to be given to the seasonal variation in demand for hydrogen, and if there is an opportunity to use the ‘spare’ hydrogen that would be generated during summer if the project continues to operate at winter capacities. As a 100% hydrogen network requires different infrastructure and appliances to a blended gas supply, the cost of making these changes will be lowest in either greenfield sites, or areas where network upgrades are already scheduled.

100% hydrogen grids provide an opportunity to maximise sector couplings, where hydrogen can be used across a number of end-uses including heating, for electricity and transport. Coupling sectors in this way is likely to be a key opportunity for scaling up the industry as any demand risks are spread, and the storable and dispatchable features of hydrogen can be fully exploited. It is not well understood however, how competitive the costs of energy supply in a complex micro-grid will be and how suitable 100% hydrogen networks are for various locations.

Deployment also carries significant capex requirements for both energy providers and
customers (appliance replacement) therefore will need continued Government support in order to progress.

Government support for demonstration projects can help build social acceptance. ARENA-funded projects include extensive community consultation, and aim to help build social acceptance by demonstrating real-life, tangible projects and familiarising the public with the concept and practice of using hydrogen for energy.
Examples of relevant ARENA supported hydrogen projects include:
ATCO Hydrogen Microgrid
- Commenced April 2018; Grant $1.66M
- ATCO believes Australia’s gas distribution network will play a key role in the future energy mix, bringing natural gas and new ‘clean’ gas, including hydrogen, to customers. This may play a central role in reducing energy costs and carbon emissions and complement the growth in intermittent renewable energy like wind and solar.
- To further explore this concept ATCO is developing a Clean Energy Innovation Hub (CEIH) based at the company’s Jandakot Operations facility in Western Australia. The Clean Energy Innovation Hub is expected to be fully operational in 2019.
- The CEIH incorporates the production, storage and use of hydrogen, as well as the commercial application of clean energy in micro-grid systems.
- The CEIH will integrate ‘green’ hydrogen created by water electrolysis – using solar energy to separate hydrogen molecules from water. The hydrogen will be captured and injected into a micro-grid system at the Jandakot facility.
- Some of the safety and technical challenges that will be tackled by the CEIH project, include optimising hydrogen storage solutions, blending hydrogen with natural gas and using hydrogen a direct use fuel.
Jemena Power to Gas Demonstration
- Commence September 2018, Grant $5.71M
- The project involves designing and constructing a Power-to-Gas (P2G) facility which will source renewable electricity and convert it into hydrogen via electrolysis. The majority of the hydrogen produced will be injected into the gas network, providing enough energy to meet the cooking, heating and hot-water requirements of approximately 250 homes. A portion of the hydrogen will be utilised, via a gas engine generator, for electricity generation, with the remainder stored for use in an onsite Hydrogen Refuelling Station (HRS).

Consideration should be given to areas where electrification is more suitable, or is being actively supported by state governments. More in-depth analysis is required of the relative costs of electrification vs conversion of gas networks to hydrogen by location across Australia. It is possible that locations with modest winter heating requirements may be better suited to electrification, while areas with large winter heating requirements may be better suited to conversion to hydrogen.

This analysis should take into account expected improvements in the energy efficiency of appliances and building stock over the coming decades. As houses and heat pumps become more efficient, and energy storage comes more prevalent, the effect of electrification of heating on peak load will decrease, changing the relative merits of electrification vs hydrogen.

The ARENA funded, Comparison of Dispatchable Renewable Electricity Options study, explored the potential role of hydrogen as an energy storage medium in the electricity sector. It highlights how hydrogen can complement low-cost variable renewable energy sources such as solar and wind by providing highly controllable output and work alongside other dispatchable renewable energy technologies.

Understanding hydrogen’s potential role as an electricity storage medium hinges on three economic characteristics: the capital cost of storage, the round-trip efficiency (power-to-power), and the capital cost of conversion technologies. The trade-offs between these cost elements determine the most economic applications of any storage technology. Hydrogen is characterised by low cost of storage, low round-trip efficiencies, and high capital cost for conversion technologies. These characteristics are discussed below.

A key advantage of hydrogen, compared to other storage media, is the low marginal cost of long-term bulk storage (e.g. in salt caverns). While the capital cost of the energy conversion technology ($/MW) is relatively high compared to other forms of energy storage, the cost for bulk storage of hydrogen ($/hours of storage) can be relatively low. This means that, in time, hydrogen may be suited for medium term to seasonal storage and as an emergency power backup where it can recoup its capital cost in the electricity market through occasional premium prices. Such an operating model could make sense where Australia has abundant capacity of variable renewable energy sources, with other storage technologies providing shorter-dispatch-duration balancing, with hydrogen only needing to provide infrequent stored energy reserves. In addition, electricity production via a gas turbine would be synchronised to the grid meaning that it may not be subject to the same administered system security constraints that currently apply to some inverter-based generation units.
A significant characteristic of hydrogen as an electricity storage medium is its low round-trip (power to power) efficiency compared to other technologies such as batteries or pumped hydro. This essentially means that the hydrogen production process requires more electricity as an input per unit of output and it is therefore more sensitive to input and output electricity prices.

The sensitivity of hydrogen production to electricity prices suggests two possible strategies for improving commercial viability as an electricity storage mechanism:
1) hydrogen production may be suited to being a ‘scheduled load’ in the electricity market where it can flexibly vary its power demand in response to wholesale price conditions and therefore support better utilisation of network and generator assets across the market. This would suggest siting in locations with high wholesale market price spreads, driven by high underlying volatility in electricity supply or demand.
2) integration with low cost wind and solar power generation at the facility level, so as to avoid transmission and distribution charges and losses, and where it can utilise ‘spilled’ electricity which is unable to be sent to market due to physical transmission congestion or an administered system security constraint on the generator. This suggests that hydrogen production may be most economically sited in areas with high solar and/or wind resource availability.

The current high cost of hydrogen conversion technology also means that production facilities will benefit from high utilisation rates so as to bring down the cost on a $/GJ basis. This duality of the need for high facility utilisation and hydrogen’s suitability for longer term/periodic power generation generation creates a significant challenge for the economics of hydrogen as a resource in the electricity sector. ARENA expects this to improve over time as technology costs come down and the industry moves to larger scale deployments. The learning rate (cost reduction curve) of hydrogen vis-a-vis other forms of energy storage is assessed in the above mentioned Dispatchable Renewables study.

If these cost factors persist, in the long term, the economic potential for hydrogen as a fuel for power generation will be greatest where it forms part of an integrated supply chain including bulk hydrogen production using variable renewable energy resources, hydrogen export capacity and peaking power generation capacity using low-capital-cost power generation technologies. For example, an interesting application may be a hydrogen production facility that principally serves an export market, but is able to draw down hydrogen stores for power generation, when the local commercial opportunity arises. As the cost and efficiency of hydrogen production improves over time, and export volumes increase, such applications could provide material support to the grid in the transition to high penetrations of renewables.

A further advantage of hydrogen is its potential (at low concentrations) to be transported via existing gas transmission networks (noting the possibility of steel embrittlement and the need for further testing of Australian gas networks) and combusted as a blended gas in gas turbine power generators. This means that hydrogen may initially be able to make commercial use of existing downstream gas transmission infrastructure while the industry builds to a scale where dedicated shipping/transmission infrastructure becomes more viable.

The connection of hydrogen production to existing electricity systems, and the expansion of electricity systems (both generation and network) to serve this additional demand, would create an opportunity for overall economic efficiency improvements because of the inherent flexibility in the timing of hydrogen production. The theoretical value of this flexibility is explained in international academic literature. For most shares of variable renewable energy, the requirement for energy storage is lower when major loads in the system are flexible (i.e. hydrogen production can be scheduled to correspond with high levels of wind and solar output when it occurs, rather than the energy needing to be stored for later use.

ARENA supports the Strategy's consideration of hydrogen as a substitute for diesel generation in off-grid power generation applications using fuel cell or gas turbine technology. ARENA’s Regional Australia’s Renewables program has demonstrated the potential for stand-alone power systems to reduce operating costs through the integration of variable renewable energy sources such as solar PV. Hydrogen offers a potential cost competitive alternative to residual diesel requirements, probably sooner than it is likely to be competitive in on-grid power generation.

ARENA considers that the issues associated with integrating hydrogen power generation into the electricity system are similar to batteries and other sources of flexible generation and load. Ultimately the power system and its customers will be best served by regulatory and market frameworks that are technology neutral, and properly value the services that are required to ensure reliable and secure operation at an efficient level.

As per the previous answer, a range of reforms are underway that will enhance the capacity of dispatchable generation to capture value from the services it provides. ARENA considers that, as we transition to higher penetrations of low-cost variable renewable energy sources, the relative value of system services markets, such as frequency and voltage control and system restart services, will increase relative to the value of energy trades. This will advantage flexible generation systems and loads that are able to provide a range of services. Hydrogen has the potential to capture a wide range of services as both a highly flexible source of generation and load.

ARENA has observed that energy customers (at all scales) are becoming increasingly sophisticated, combining low cost variable renewable energy generation with energy storage and load flexibility to meet an increasing share of their energy needs. The efficient adoption of hydrogen production, storage and power generation, at industrial customer premises is most likely to be achieved by technology neutral regulatory and market frameworks that allow customers to adopt new technologies and management practices flexibly based on transparent performance requirements set at the point of connection to the grid.

As mentioned above, the economic potential for hydrogen as a fuel for power generation may be greatest where it is part of an integrated supply chain including bulk hydrogen production using variable renewable energy resources, hydrogen export capacity and peaking power generation capacity using low-capital-cost gas turbine technologies. Trials and studies that explore how these elements can be effectively integrated will be important in demonstrating the technical and commercial potential for the integration of hydrogen technologies into the power system. Factors for consideration in the selection of these projects will be the potential impact for the sector, the pathway to commercial viability, replicability of the project and the level of support by way of co-funding. Projects should also be robust and well planned, with a proponent that has the appropriate capability and capacity to execute.

- Hydrogen Mobility Australia members:
https://www.hydrogenmobilityaustralia.com.au/members
- Greenfield property developers - incorporating assessment of FCEV/BEV vehicles with master planned areas i.e. waste disposal, bus fleet, campus light transport, or industrial properties with material forklift usage

a. ARENA has noted interest from vehicle manufacturers (primarily Toyota and Hyundai) in raising awareness in FCEVs as an alternative to BEVs:
i. local council 3-month trial of FCEVs
https://www.toyota.com.au/news/toyota-partnering-with-melbourne-council-for-au stralian-first-hydrogen-fcev-trials
ii. demonstration of refuelling vehicles from majority renewablly sourced hydrogen https://www.toyota.com.au/news/toyotas-altona-site-to-be-home-to-victorias-first-hydrogen-refuelling-station
b. Fleet owner / operators (such as public transport networks) have expressed interest in investigating hydrogen-fuelled vehicles as part of a fleet upgrade process, citing suitability of fast refuel for back-to-base operations.
i. Bus / Ferry: Under the public transport sector’s current framework, owner/operators of public transport assets bid for service contracts from the government public transport authorities (e.g. Transport for NSW). Proposals are assessed against a set of criteria including price, reliability, capability and sustainability. To address the criteria, the bidding consortium should consist of an owner/operator, OEMs and funding bodies. OEMs must ensure that equipment is designed to be safe, reliable and efficient. Funding bodies (e.g. private investment or government grant programs) need to design effective models to bridge the economic gap between traditional transport (ICE buses) and FCEBs. The consortium will then need to secure an economic offtake agreement for Hydrogen before submitting its proposal to the relevant public transport authorities, whose support is essential for implementation.
c. Logistics / Trucking: ARENA has received interest from private companies to introduce FCEVs into operations, however, lack of reference demonstration projects, vehicle availability, availability of technical expertise in design and implementation and capital cost of electrolysers cited as key barriers.

a. Federal: Concessional funding for demonstration projects and innovation development
b. State: Streamlined property development applications where innovative low-emission options are included (e.g. waste disposal trucks, local bus).
c. Local: Raise awareness (i.e. Hobson’s Bay Toyota FCEV trail); potential public refuelling site owner/operators.

a. Be technology-agnostic in assessing the merits of various projects to reduce fossil-fuel usage in transport.
b. Support FCEVs in niche applications where characteristics of hydrogen as a fuel potentially presents a better fit for purpose (i.e. forklifts).
c. Proactive identification of strategic refuelling sites where multiple users can make use of larger electrolysers (i.e. industrial parks, existing petrol stations).

a. Small-scale refuelling and back-to base fleet demonstration projects
b. Public awareness: Drive days and car sharing initiatives

a. Forklifts: Existing (small-scale) trials at Toyota’s warehouse
https://www.toyotamaterialhandling.com.au/news-resources/press-room/2018/toyota-fork lifts-leading-hydrogen-charge/
b. Passenger Vehicles: The Australian Electric Vehicle Market Study found that cost, model choice and performance were key drivers of technology switching for passenger vehicles, and indicates that uptake of FCEVs as passenger vehicles is likely to be slow.
c. Buses, freight, mining vehicles: Key enabler will be vehicle availability.

In general, energy productivity/energy efficiency and renewable heat technologies including bioenergy, concentrating solar thermal and electrification (electromagnetic, electrical resistance, and electric arc), have application across manufacturing sectors, including metals manufacture and provide pathways to reduce or eliminate carbon emissions. For steel in particular, biochar is an alternate approach to hydrogen reduction, however supply of feedstock would likely be challenging at scale. Improvements in efficiency also represent an important means of lowering GHG emissions and can be done with commercially available equipment.

Industrial users currently overwhelmingly use fossil fuels for heat with the notable exceptions of the sugar industry, which uses a substantial amount of bagasse, and the pulp and paper industry which uses a substantial amount of wood and wood residue . At lower temperatures, bioenergy, heat pumps and other electro technologies are being considered by some industrials. At higher temperatures, biogas, concentrating solar thermal and electrotechnologies may be considered. Cost-competitiveness is very site - and application - specific and depends on factors including but not limited to :
- current energy costs (noting there is a wide range in costs for small vs large users)
- equipment capacity factor; renewable energy/fuel supply availability and cost (esp. bioenergy)
- flexibility in process and consequent requirements for thermal or other forms of energy storage
- opportunity and viability of reducing demand for heat through better heat recovery, heat integration and process change (e.g. mechanical dewatering vs evaporation) etc.
- other productivity gains afforded by alternate technologies such as faster processing (e.g. electromagnetic drying versus conductive), shorter batch times).

In general, other than the examples above, industrial users are at an early stage of considering renewable alternatives for heating however some Australian and international case studies across a variety of sectors are provided below:
Alumina refining
-Alumina is an intermediate product between bauxite (the ore) and aluminium. Alumina is produced via the Bayer process, which is a two stage process, the first being a low temperature digestion stage at 200°C using steam heating, and the second a high temperature calcination process that occurs at 1000°C, generally using natural gas.
- Most alumina plants use natural gas as the fuel of choice for calcination, although heavy fuel oil continues to be used in some places. Coal is also used, either directly for steam raising, or indirectly via syngas for calcination. There has already been niche uptake of renewable energy sources. For example, South32 uses biomass as a part-replacement for coal in steam raising. There seems to be no technical barrier to the use of hydrogen, although the presently high cost means that little work is being done to explore its use commercially.
- A consortium (University of Adelaide, CSIRO, Alcoa, Hatch, ITP and UNSW) is taking a three-pronged approach to identify a realistic path to achieve a 50 per cent solar share in the commercial Bayer alumina process based primarily on a cost target of displacing natural gas at AUD$10/GJ, using CST for digestion, reforming natural gas to produce syngas, and for calcination. Each of the three stages is considered to have good potential to meet the target, albeit with some support needed for first-of-a-kind development and demonstration.
- Electrically powered mechanical vapour recompression (MVR) has also been analysed and compared for the low temperature digestion process.
- The calculated IRR of MVR depends on the electricity price assumed, but positive values are achievable. The comparison of solar thermal and MVR strongly depends on the assumed electricity price. Solar thermal is predicted to yield favourable economics for electricity prices above around 7c/kWh while MVR is predicted to be more favourable below that .
Food and beverage
- Solar Energy for Winery: De Bortoli Winery installed a solar thermal evacuated tube collector system at its Griffith winery in 2013. This system was designed to reduce gas consumption for hot water by more than 80% over the year. De Bortoli Winery received a $4.8m Clean Technology Food and Foundries Investment Program grant to contribute to the plant upgrade and expansion that was forecast to cost $14.5m. Simple payback was approximately 6 years excluding grant funding.
- Electric Infrared Preheating in Aluminium Forging: Queen City Forging in Ohio, US makes components for transport and agricultural equipment. The company heats aluminium billets to 425°C prior to hot-forging. Previously this preheating was achieved using gas-fired convection furnaces in batch processes. By switching to a new electric powered convection-infrared hybrid preheating furnace, the company has reduced costs and energy use, while increasing throughput, quality and consistency. Energy demand reduction of 65% per tonne of product and 40-50% energy cost savings.
Cement and Lime
- Alternative Fuel in Cement Manufacturing: Adelaide Brighton’s Birkenhead, SA gas-fired cement kiln has the capacity to produce 1.3 million tonnes of cement products per year. In 2003, the kiln commenced using more than 70,000 tonnes of recycled construction and demolition timber per year as a supplement to natural gas. A reduction of 20% in natural gas consumption was achieved.
- Waste to Process Engineered Fuels Production Facility: In 2018, Cleanaway ResourceCo opened a new waste recovery plant in Wetherill Park NSW, western Sydney. The plant diverts waste from landfills and provides a fuel to displace coal usage at the Boral cement plant in Berrima NSW as well as for other industrial customers. At the NSW Boral cement kiln, it is expected that 100,000 tonnes of process engineered fuel from the Wetherill Park plant will replace 50,000 tonnes of coal each year.
-Concentrated solar thermal : A number of projects around the world are seeking to develop methods to use CST for the high temperature calcination process, either intermittently or after storage. While the temperature of calcination, at around 850°C, is compatible with CST, further work is needed to identify practical approaches to integrate the variable resource within a continuous process and within the constraints of an operating plant. This challenge is similar to that of alumina calcination.
Glass and ceramics
-Brick – microwave assistance: Several pilot studies have shown that the time and energy required to fire bricks can be reduced by using microwaves to supplement conventional kiln firing. In a microwave-assisted kiln the bricks are heated simultaneously from the outside by conventional heating, and from the inside by microwave heating. This technique means the bricks can be heated rapidly and evenly, ensuring no damage occurs. Faster firing means less heat is wasted and energy efficiency is increased.
- In one UK study a conventional gas-fired tunnel kiln was fitted with two 60 kW microwave emitters. It was found that this tunnel kiln, with microwaves supplying just 10% of the total firing energy, reduced energy consumption by 50%. The microwave-assistance also reduced the firing time from 46 hours to 16.75 hours – an increase in production speed of 174% (UK Government, 1999).
-Microwaves could be retrofitted to most existing brick kilns, and the technique could also be applied to almost any kiln-fired ceramic product, such as tiles and kitchenware
-Glass – electrical resistance: All stages of glass production could be electrified and indeed there is commercially-available equipment to enable this (Lord, 2018). The most energy-intensive step in glass-making is melting the raw materials, which accounts for around 75% of the energy requirement. Globally, many modern gas-fired glass melting furnaces are fitted with electric boosting which contributes 5-20% of the heat (Worrell et al., 2008). The biggest advantage of electric glass melters is their energy efficiency. By passing a current through the raw materials they generate heat within the charge through electrical resistance. This results in lower heat losses and the best electric glass furnaces can achieve an efficiency of 87%, a 37% improvement on an average conventional gas-fired furnace. Electric glass furnaces have several other advantages including higher-quality output, reduced capital cost, less maintenance and lower toxic emissions.
Wood and wood products
- Radio frequency glue curing: Most Engineered Wood Products (EWPs), such as glulam and cross-laminated timber, are made from separate timber pieces held together with strong adhesive. This glue must cure before it develops full strength. Some manufacturers of timber products cure glue by heating the EWPs in a gas-fired kiln for up to 8 hours, Table 22 (Lord, 2018). In Europe, EWP manufacturers increasingly use radio-frequency heating to cure glue. Danish company Kallesøe Machinery makes equipment which uses radio-frequency heating to cure and set EWP glues in less than 20 minutes, many times quicker than any alternative curing process. Radio-frequency curing is also extremely energy efficient as it heats only the glue, without heating the wood at all. Compared to curing in a gas-fired kiln, it uses less than 10% of the energy.
Green steel (as covered in Q1)
- Globally there are commercially mature advanced iron production methods based on direct reduction using gas mixtures produced from natural gas. These are then followed by electric arc furnaces for the final stages of steel making. These can be the basis of future systems that use renewable hydrogen but requires the construction of completely new facilities. Whilst not yet cost effective, if the world moves to emissions free Iron and Steel, Australia has both the iron ore and renewable energy resources to be a competitive provider in that context.

Yes. See maps in attached document. Figure 1 for existing major industrial heat users;

For solar resources, Figure 2 for Direct Normal Irradiance (relevant to solar thermal); and Figure 3 for Global Horizontal Irradiance (relevant to solar PV systems).
For wind resources, see https://aera.ga.gov.au/#!/wind

There is high current demand for hydrogen for ammonia facilities located in the northern half of Australia, which has high quality solar resources. The Pilbara region of north west WA, which produces much of Australia’s iron ore has world-class solar resources, and could provide a location for future production of steel using hydrogen. The level of solar resource for the WA and Gladstone alumina refineries is quite good (average DNI ~2,100 kWh/m2/year). The resource at Mt Isa or Olympic Dam is on the other hand close to the best in Australia (~2,500 kWh/m2/year).

What existing sites might be suitable to demonstrate industrial use of clean hydrogen?: Ammonia production facilities.

The discussion paper identifies that industrial use of hydrogen is a long-term transition and identifies actions along the transition pathway for industrial users from 2020 to 2030. It is expected that ARENA’s funds will be fully committed in the next 12-18 months, and therefore ARENA will be active only in the early stages of the industry’s development.