Hydrogen Headstart Program Consultation

TRL (technology readiness level). If H2Head (hdyrogen headstart) wishes to source, deploy and scale H2 to a new market equilibrium price of $2/kg, then ignoring any emerging {renewable energy -> hydrogen carrier -> storage/transport/uptake} tech within the 10 year subsidy period will favor mature COTS pathways (eg ammonia). In my professional role as IP broker, I can point to alternatives such as metal hydrides which are at a lower maturity level, but offer the potential to be thermally stable (solid without the compression/boiloff losses). However, commercialisation of this and alternative pathways (eg liquid organic hydrogen carriers) requires a risk-reduction approach of kgs -> tons -> Mtpa with commensurate energy & plant requirements.

Recommendation - allow for TRL to be a mitigating factor ONLY for NOVEL H2 pathways within the 10 years.

Notes: There may be some quibbling on definition of novel, but for purposes of H2head, it can be defined as 2nd time (outside home lab) being deployed in ASEAN+2 (factoring in the feasible export market) or close variations at discretion.

Given that commercialisation of H2 innovation requires progressive derisking, no R&D intensive firm would jump straight to 50MW from lab. Progressive steps may be a) pilot = batch operation with consistent yields (kgs) b) demo - 100 day continuous flow within a calendar quarter (tons) c) scaleup = 1 year uptime over a period of say 2-2.5 years for learn-by-manufacturing and improve uptime/reliability.

Recommendation - apply a technology-neutral risk-adjustment scaling factor for minimum deployment size.

Notes: Eg 2-norm of sqrt{TRL primary renewable energy ^2 + TRL hydrogen carrier conversion ^2 + TRL hydrogen offtake^2) x 50 MW. The goal being to ENCOURAGE SCALING to the desired capacity by END of 10 years with credible evidence that the offtake product at scale can meet desired goals of H2head (despite the cautious pilot-demos initially). Variations might be weighing the norm components, preferring mature renewables but allowing more H2 offtake diversity. This allows decomposition of existing sites which may be adding in marginal capacity but claiming outsized subsidy relative to potential supply-price shift.

There are 3 economic objectives conflated within the question. a) economy of scale - to force supply-demand equilibrium to the stated objective of $2/kg; b) economy of scope - allow for multiple pathways to satisfy multiple domestic and export markets; and c) economy of density (spatio-temporal arrangements) as per the Net Zero Australia scenarios. Following the Cynefin framework for knowledge management, scale issues are simple, scope are complicated (tradeoffs) but density is complex. If there is INSUFFICIENT data to make rational market decision,s the suggested approach is to PROBE, SENSE and respond. We can model the proposed H2 market as a hidden markov model with observable variables being the market price of H2 and volumes generated/sold. The aim of a suite of project sizes is to elicit from market participants the hidden variables (yields, WACC, etc) to determine the most capital efficient deployment and location of the {primary energy, hydrogen carrier, end offtaker). This then could evolve into a time-inhomogenous variable length markov chain to trace where the subsidy is actually shifting along the Scope 2 (generation) -> Scope 1 (conversion) -> Scope 3 (transport/consumption) of the hydrogen carrier.

Recommendation: consider project suites where there is insufficient information to form a market (thin, opaque, illiquid) as a testbed will allow for emergent rule make to foster contestibility

Notes: Market design for common-goods (land use for solar) is difficult but not impossible. An example might be to encourage (or force) transferable PPA (10 year power purchasing agreements) of renewable energy and couple with (5+5 year option) of H2 offtake. By using new DLT technologies such as fractionalisation and atomic operations, you can offer early H2head participants an exit route for more efficient operators who come later. Eg buyout of an H2 offtake option to export metal hydrides instead of low-complexity (and value-add) of ammonia, instead of locking in exports to a suboptimal product mix.

This relates to the economy of density issue which is connected to the cost of H2 carrier choice and transport (gaseous, liquid, embodied NH3, hydride, etc). A preference for single site would constrain the options for land transport offtake of H2 (cf ATCO abandonment of 10MW hydrolyser being too far away from industrial users). A preference for multiple sites might not achieve economies of scale and reach the objective of $2/kg H2. Policy objectives then become multi-criteria as it might not be feasible to achieve both (broad participation & scale).

Recommendation: related to Q2.3 in market design in having standardised (or severable) PPA/H2 offtake agreements that can be transferred within the 10 year period.

Notes: In Deeptech this is known as market annealing where there may be multiple deployment options but allowing market participants to learn-by-doing and having a floor to economic losses with a (semi-)liquid market to dispose of the contractual obligation to provide hydrogen in case of miscalculation.

The rules for the subsidy should be considered in light of policy objectives. Given that overspending on capital and requesting a large production credit only crowds out more efficient (but smaller) projects, some thought should be given as to the law of unintended consequences. Within the Cynefin framework, the response may be the criteria under which the rules are changed (eg the 50% benefit sharing). For example, if information is revealed that participants are rorting the system via collusion, what actions can (or should) be taken? These guardrails to protect the public interest can be reserve powers (cf Q2.4 on market design) but should be spelt out to avoid Enron-style fake emergencies. The stated objective of H2head is to accelerate the early stage of S-curve adoption by forcing the supply-price and theoretically drive the demand curve upwards. Given the fragmented nature of Australia renewable energy sites and opportunities to create artificial supply-demand gaps or disadvantageous transfer pricing, what should be done to protect the taxpayer?

Recommendation: Rather than being overly prescriptive, legal realism would point to publishing a set of H2 market accepted practices (from observing industry) and a set of reserve powers to correct failures.

Notes: The information collection can be in conjunction with the measurement, reporting and verification process (RE/GO etc). It is not widely known but hydrogen has 14x the greenhouse effect of CO2. It would seem contradictory in subsidising a more "polluting" industry than the original fossil fuel it was intended to substitute for. If there is insufficient data to design market rules, then a clear process on how rules are modified should be given.

See Q2.5 (output rather than input) in the markov chain

This question is really about whether there are (or should/should not be) artificial discontinuities in the market design. HVDC transmission lines have known losses ~3.5% per 1000km, liquid hydrogen has boiloff of ~1%/day (cf LNG ~0.1%). Solid metal hydrides have no transport losses but higher hydrogenation costs. If the objective of H2head is to shape the choice of hydrogen carrier (gas/liquid phase, chemical composition, value-add), then what is the goal? If the goal is to be market agnostic, then you can define ton-km functions and allow states to adjust for their specific resource configuration. For example, the Net Zero Australia E+/ONS scenario would be favored by WA (using renewables for direct reduction of their ores to metals) whereas NT might prefer the E+/RE-- with Carbon capture to exploit proximity to Asia. Premature conditionality on destination may prejudice or even distort decision making or location of projects. Individual states (or shires) may offer additional incentives but without an initial level playing field, it would be difficult to compare and contrast these export or reservation policies.

Recommendation: Be neutral and foster a competitive but transparent market for H2 and allow participants to select (or subsidise) their preference.

Notes: Past the 10 year production credit, there is still the on-going transition to Net Zero 2050. The more capital wasted in inefficient projects, the higher the long-term borrowing cost and thus burden on tax-payer. If there is a need for directed industrial policy to climb the transformation complexity, then is it more or less effective to con-mingle with a market design? It is possible but requires consensus as what is "beneficial" and not short-term beggar neighbour (cf Asian crisis devaluation) thinking.

Measurement, reporting and verification should be a key part of market design and improvement. Unfortunately fugitive H2 emissions are not as observation as methane or thermal blooms from fossil combustion. In addition, history has shown that industry is ... sparse in reporting where there are economic disincentives (cf Nigeria gas flaring). Given the high uncertainty in process modelling at the early application stages, it would be hard to distinguish a genuine oversight or deliberate gaming.

Recommendation: Separate to the H2head production subsidy, have a fee-bate system where the RE/GO audit allows for reduction of the lowest x% and reward the highest (lowest emission) x% H2 producers.

Notes: as there is high uncertainty, perhaps this can be introduced after a settling period (5 years?) and then based on independent MRV process, remove and reward subsidy to encourage the worst performers to exit (eg selling their PPAs) and reward participants that achieve the emission objectives (potentially covering wider industry, not just H2). This will slowly converge the RE and existing industry over a transition period.

Would appreciate some more independent modelling on the supply-demand curves and their spatial distribution. Natural gas (even with LNG) with their high transport costs are regional markets and given the expanse of Australia, East/West coast are effectively separated so difficult to formulate a unified market price for H2 analogous to the NBP of UK (for gas). Without market signals, it is challenging to determine whether policy is having effect in achieving the desired $2/kg goal, much less detecting gaming the design.

Hydrogen is an energy carrier between primary sources (renewables) and final energy (heat, power, propulsion, chemicals, etc). As intermediary it can be stored/transported in multiple forms, and even imported. There may be a situation where SMR H2 could be imported (cf Methanex in NZ) so consideration should be given to a border adjustment mechanism like EU so reimports of transformed energy with Australian origin is not disadvantaged against chemicals produced using high carbon emitting sources.

See response on export.

So long as satisfies Foreign Investment Review Board criteria, then under various international Free-Trade agreements there should not be any discriminatory or preferential access. Industry attraction initiatives have historically be left to individual states.

Unless the $2B is inflation adjusted, then question is moot. The goal is to motivate industry to scale to achieve $2/kg target, not an infinite life-support so the production credit should be slowly tapering offer (see notes on fee-bate on inefficient producers).

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How is the market price determined?

See notes on TRL and innovation.

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If the subsidy is tied to GST as temporary arrangement, then it would be tracked via existing invoicing and payment between (hopefully) arms-length market participants.

Is what is measured, countable (independent verification. Because what counts, may not be measurable (technology innovation and energy efficiency).

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See notes on transferable PPA and hydrogen offtake

Adoption of new value-add pathways for embodied energy (increasing economies of scope).

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Issue whether this is a one-off competitive round or if there are failures (and unallocated subsidy), whether there should be multiple rounds (eg at 5 year intervals)

Some of the participants may not be 100% certain at EOI stage. A co-operative should be allowed to enroll/exit members so long as the overall project is broadly maintained.

Where there is new technology for hydrogen carrier, a risk-adjustment to alter the schedule and/or size of deployed plant should be flexible provided the overall project is broadly maintained.

International role of AUKUS pillar 2 may alter some of the export consideration.