Submission: Hydrogen Headstart – Round 2

The Australian Pipelines and Gas Association (APGA) represents the owners, operators, designers, constructors and service providers of Australia’s pipeline infrastructure. APGA members ensure safe and reliable delivery of over 1,500 PJpa of gas consumed in Australia alongside over 4,500 PJpa of gas for export.

APGA welcomes the opportunity to contribute to the Australian Renewable Energy Agency’s (ARENA) consultation on Round 2 of the Hydrogen Headstart program.

APGA agrees with ARENA that renewable hydrogen is critical to developing an emissions-free product manufacturing industry, and realising the considerable value-add of exporting those products in lieu of raw materials. Developing a viable renewable hydrogen industry is hence critical to enabling the Federal Government’s vision for a Future Made in Australia, and our economy in a net-zero world.

But even with fast-tracked investments and supports like the Hydrogen Headstart (H2H) and Hydrogen Production Tax Incentive (HPTI), producing renewable hydrogen is difficult and expensive. In Australia large-scale projects will likely not produce significant quantities of hydrogen until well into the 2030s. Australia needs renewable gas at scale well before this.

Thankfully, renewable hydrogen is not the only road to Rome. Biomethane is a net zero gas and can be immediately substituted for natural gas in transmission and distribution infrastructure. With the right policy settings, biomethane can both complement green hydrogen, and bridge the gap between now and when green hydrogen production scales up to provide sufficient volumes.

Renewable Gas Headstart

APGA recommends that the H2H program be expanded to include biomethane, to create a “Renewable Gas Headstart” that will enable biomethane and renewable hydrogen to be developed on equal footing.

The role of biomethane in Australia’s future fuel mix under a least-cost decarbonisation pathway was demonstrated in ACIL Allen’s recent modelling for a Renewable Gas Target.[1] Biomethane will be critical today and in the near future, well ahead of delivery of significant volumes of hydrogen from the late 2030s (Figure 1).

Figure 1: Projected fuel mixes of current gas users under an Optimal Renewable Gas Target (PJ)

Biomethane is an internationally mature technology, with conservatively 132,000 medium- and large-scale anaerobic digesters and 700 upgrading facilities operating globally.[2] In Australia however the industry is experiencing challenges in scaling up project investment. Similar to green hydrogen production, these challenges are largely related to initial costs before scale can be achieved.

Enabling a biomethane stream

A biomethane stream for H2H would require rescaling of the eligibility thresholds. The largest biomethane production facility in Australia, Jemena’s demonstration biomethane plant in Malabar,[3] can currently produce 95 terajoules of renewable gas annually.

While the largest facilities in Europe can produce up to 1,500 TJ per annum, it is unlikely that facilities of this size will be proposed in Australia in the early stages of biomethane industry development. Conservative estimates of Australia’s biomethane potential is in the tens of petajoules per annum.[4]

The H2H minimum hydrogen electrolyser size is 50MW. An electrolyser of this size can produce approximately 22,000kg of hydrogen per annum, equivalent to about 730 TJ per annum.

It is worth noting that APGA has also argued that a biomethane stream should be made available in the HPTI.[5] The HPTI of $2/kg of green hydrogen equates to $14/gigajoule[6] - a significant incentive for investment. Biomethane from upgrading landfill gas would become available at a cost considerably lower than the current premium, making viable many currently marginal projects which produce biomethane from anaerobic digestion.

Figure 2. Expected costs of biomethane by source, to 2059 ($/GJ)[7]

Consultation questions

Proposed eligibility requirements

Question 2.1: Considering the eligibility requirements outlined above, please comment on whether these eligibility requirements are appropriate for Round 2.

Project size

While H2H does not specify an end use for green hydrogen product, the program was originally conceived with a vision of supporting very large scale green hydrogen production, much or most of which would be exported. This industry has not yet developed in the way it had been intended, largely due to the fact that transporting green hydrogen molecules adds technological complexity and hence expense.

AEMO has recently revised its assumptions for hydrogen production in Australia to reflect this in its scenarios, with hydrogen electrolysers locations in Renewable Energy Zones rather than close to ports.[8] This also acknowledges that green hydrogen production for domestic use, rather than bulk export, is more likely.

This means that the minimum size of electrolysers may also need to change. 50MW for a single site is five times larger than the largest electrolyser project under development in Australia[9]. The single site requirement itself may also act as a barrier, where rendering ineligible “distributed production across multiple geographically diverse sites” many restrict the actual trajectory of green hydrogen development in Renewable Energy Zones.

APGA strongly suggests that these criteria be revisited.

Project end use

The proposed framework considers gas blending into networks to be a specific end use, when in reality gas blending is largely a transport mechanism. By way of comparison, considering blending as an end use would be similar to considering liquefaction as an end use (where the end use is in fact export).

This is inconsistent with other existing regulations where the renewable benefit is linked to certificate purchase ownership, not physical delivery infrastructure.

Production pathway

The H2H presently specifies that hydrogen must be produced using electrolysis of renewable electricity. This approach is unnecessarily restrictive.

If ARENA considers it necessary to apply a product threshold, a better approach than excluding specific technologies would be to specify a carbon intensity threshold. The HPTI, for example uses an intensity threshold of 0.6kg CO2e/kg.

APGA further notes this intensity threshold is very low relative to international standards. The UK’s Low Carbon Hydrogen Standard threshold is 2.4kg[10], the EU’s low carbon hydrogen threshold is 3kg, and the US’s Clean Hydrogen Production Standard is 4kg.

Funding allocation and assessment process

Question 7.1: Please comment on whether the proposed alternative assessment approaches could be appropriate for Round 2.

The design of the H2H, with discrete funding rounds, reflects an industry that is much more developed than the reality of green hydrogen in Australia in 2025.

Hence APGA strongly supports Alternative 2 – an open and ongoing program, similar to the Advancing Renewables Program. This would reflect the fact that projects may reach bidding capacity at different times, and avoid the current situation where proponents are effectively required to submit their bids potentially before major aspects of their project have been resolved. Adding this flexibility would likely encourage more and better submissions for project development, rather than an arbitrarily fixed and inconvenient timeline.

The current approach may result in lower quality submissions that would otherwise have been reached if proponents were able to submit if and when they were ready to do so. ARENA could also consider extending the guidance approach of the Advancing Renewables Program to H2H, which would have the benefit of addressing potential shortfalls in submissions early.

Bid bond

Question 13.1: Is the requirement of placing a bid bond upon receiving an Offer to Negotiate a reasonable mechanism to ensure project delivery commitment?

While the concept of a bid bond is reasonable, in practice this will require strong exemption regimes to not act as a barrier to participation in the scheme. It is not clear precisely what is meant by “realistic pre-estimate of the costs in seeking a replacement project” for this risk to be reflected in project bids.

The bid bond concept also does not provide for the potential reality of force majeure events on project timelines or ultimate viability. APGA strongly recommends that ARENA develop a robust set of guidelines and an exemptions framework alongside the bid bond to ensure proponents are not unnecessarily penalised for circumstances affecting their project outside their control.

[1] ACIL Allen, 2024, Renewable Gas Target: Delivering lower cost decarbonisation for gas customers and the Australian economy, https://apga.org.au/renewable-gas-target

[2] World Biogas Association, 2019, Global Potential of Biogas, https://www.worldbiogasassociation.org/wp-content/uploads/2019/09/WBA-globalreport-56ppa4_digital-Sept-2019.pdf

[3] Jemena, 2024, Malabar Biomethane Injection Plant, https://www.jemena.com.au/future-energy/future-gas/Malabar-Biomethane-Injection-Plant/

[4] ENEA, 2021, Australia’s Bioenergy Roadmap, https://arena.gov.au/knowledge-bank/australias-bioenergy-roadmap-report/

[5] APGA, 2025, Submission: Senate Inquiry into the Hydrogen Production Tax Incentive Bill, https://apga.org.au/submissions/senate-inquiry-into-the-hydrogen-production-tax-incentive-draft-bill

[6] This conversion uses the “higher” 143 GJ/tonne energy content factor for hydrogen, as listed in the NGER Measurement Determination, Schedule 1–Part 7—Energy commodities.

[7] ACIL Allen, 2024, adapted from estimates published in Australia’s Bioenergy Roadmap.

[8] AEMO, 2025, Draft 2025 Inputs, Assumptions and Scenarios Report Stage 2, https://aemo.com.au/-/media/files/major-publications/isp/2025/stage-2/draft-2025-inputs-assumptions-and-scenarios-report-stage-2.pdf?la=en

[9] AGIG’s 10MW electrolyser currently under construction for its Hydrogen Park Murray Valley facility in Wodonga, Victoria.

[10] This conversion uses the “lower” 120 GJ/tonne energy content factor for hydrogen.