National Hydrogen Strategy Issues Papers

How can hydrogen production best be integrated with current electricity systems (for instance, should large-scale hydrogen production be connected to current electricity systems)? Are there barriers or risks to integration that need be addressed in the Strategy?


Using traditional electrolyser technology, adding large-scale hydrogen production to the electricity grid has the potential to both lift demand for more expensive gas-fired dispatchable power as variable renewables penetration increases, whilst exacerbating viability of the hydrogen plant due to either/both input costs or utilisation of plant. Viability may only be achieved after 2030.

The economics of green hydrogen production using renewables can be vastly improved if instead grid connected Nickel-Iron Battolyser technology was used. A Battolyser is a battery that also produces hydrogen and in simple terms operates under three modes "charge", "discharge" and "overcharge/hydrogen production". The technology has been developed by TUDelft and being trialled with Nuon Vattenfall in the Netherlands at the Magnus Power Plant based on the hydrogen-producing flaw of Thomas Edison's 1901 nickel-iron battery technology.

Like the Hornsdale Power Reserve, a Nickel-Iron battery can engage on all segments of the NEM FCAS market (regulation and contingency, raise and lower), the energy market, and any emerging sub 6 second contingency markets. Like Hornsdale, consumer energy prices can be kept lower by undercutting gas peaking power.

Based on data from Neoen, Hornsdale Power Reserve has proven to be a highly profitable market participant. However asset utilisation analysis of the Hornsdale Power Reserve shows that their is a large opportunity to use parts of the battery for other purposes throughout the year: if only there was something we could use this asset for?

Enter the Battolyser technology.

A detailed concept stage techno-economic analysis using ACCC, AER, Platts, LME and TUDelft data applied to various scenarios in NSW using the up to 400MW FCAS dispatch in the NSW NEM region at the prevailing market rate suggests that less than $8/GJ HHV equivalent Hydrogen can be produced, which translates to less than $2/kg Hydrogen. Electrolysers seem unable to match this in the short term. The highly competitive green hydrogen makes the proposed import terminal at Port Kembla with $10/GJ or $12/GJ natural gas seem ridiculous. Sensitivity analysis suggests that the economics improve with increasing scale up until the FCAS market is fully serviced, however varying the battery/hydrogen utilisation ratio can maintain profitability and competitiveness against natural gas at smaller scales too. Increased renewables penetration and closures of Coal such as at Liddell would obviously increase the potential for FCAS. I note that the techno-economic analysis assumed Sea Water Reverse Osmosis (SWRO), which makes the hydrogen production drought immune. The presence of SWRO makes negligible effect on the economics.

Green hydrogen that is cheaper than natural gas on an energy basis, along with large storage such as in a gas grid would facilitate the possibility of seasonal energy storage to potentially use existing peaking gas plant in a new “winter” role, such as potentially arranged at the Newcastle Gas Storage Facility operated by AGL.

Barriers and risks to integration are from the displacement/supply of FCAS by Snowy 2.0 undermining the economics at the larger scale, the availability of large scale low priced renewables connected to grids (green energy supply and FCAS demand), the proximity of existing deep water ports and ammonia plant (Gladstone, Newcastle) and their technical scope and Orica’s interest for expansion, the timing of various actors including coal retirements, Japan/Korea demand for green hydrogen and Japan/Korea reduction in thermal coal demand from Australia, especially thermal coal exposed Newcastle. Finally, the battolyser technology is still requires some development effort to progress along the innovation cost curve and meet the fundamental cost my analysis reveals.

Grid connected hydrogen plant should be promoted to engage in demand response and FCAS. The NEM should reward high speed precision FCAS supplied by systems like grid scale batteries. All states should consider a non-market state government controlled energy security reserve clause for market participant hydrogen plant similar to the Hornsdale Power Reserve with the South Australian government.

GW scale grid connected hydrogen plant using Battolyser technology can provide governments with surety under a range of “non-credible” contingency events that would otherwise lead to an SA like black system outcome. Note that a battolyser operating in hydrogen production mode is “fully charged” from the point of view of grid services.

Variable renewables should be encouraged to seek contracts with grid services providing hydrogen export plant, even over alternatives like grid batteries, to provide dispatchable renewables when they connect to the grid.

The timeframe should be to legislate or regulate so that projects can proceed in time for coal plant retirement. Liddell’s retirement is proceeding with pumped storage and battery options because no real place for hydrogen export has been made by Australian governments.

Several factors conspire against market:

A 5 minute settlement & dispatch regime must be bedded in rather than the 5 minute dispatch / 30 minute settlement regime on the NEM.

An additional high speed (1 second, or less) response contingency up & down within the FCAS market should be created to reward the stabilisation effect that grid batteries and the hydrogen battolyser have upon the grid.

The sector coupling, whilst present, lacks transparency. For example gas fired electricity often involves private contracts with limited market visibility, and certainly not low friction interactions.
Similarly, the limited electric vehicle install base has been accompanied with a relative blindness to the effects either at a distribution network view or to a grid operation & generation point of view.

Information sharing, perhaps using anonymising techniques, is required across these interacting markets.

An important factor that should be considered for pilot projects is the value to kick start an energy transition from coal for local communities.

Another important factor is the availability of a deep water port for export operations so that a scale can be achieved which will deliver lower cost hydrogen.

The presence of existing ammonia plant and industrial electric load and related social license.

I note that the LaTrobe and Hunter Valley areas both are seeking transition opportunities. However I would argue that Newcastle is in a far better position to take a pilot to scale because of the confluence of many of these factors. I note also that the Kooragang Island Hexavalent Chromium incident can actually be turned into a social license virtue if the root cause steam methane reformer were replaced with a green hydrogen alternative. LaTrobe must instead wade through Ramsay wetland issues to make a port where there is none.