1. What certification framework are producers more likely to participate in to create RFS certificates for eligible green hydrogen and renewable methane?

Both certification schemes have their benefits and downsides. GreenPower is an administratively simple scheme which establishes a trading market for RGGO certificates. It falls short by limiting renewable gas end-users to commercial and industrial customers. This restriction artificially limits the potential offtake, which both raises the cost of the product to consumers and reduces the economic value of scaling production, and dampens the willingness to pay signals.

The GO Scheme’s Product GO certificates may fill this gap, but it is an administratively complicated scheme which itself is a disincentive for participation relative to GreenPower.

APGA recommends the NSW Government engage with GreenPower towards expanding the scheme to ensure it provides parity with Product GO certificates on end use.

2. What challenges could arise for producers demonstrating local use?

APGA considers that local use should be demonstrated primarily through retirement of the relevant renewable gas certificate for eligible use in NSW, with appropriate controls against double counting. Requiring producers to additionally demonstrate the ultimate physical consumption location of gas supplied through common-use pipeline infrastructure would create unnecessary complexity. Once renewable gas is injected into a gas network it is transported and settled as part of the broader gas supply, rather than physically traced to an individual end user. This is consistent with the book-and-claim approach for RGGO certificates.

The certificate framework provides the appropriate mechanism for attributing the renewable characteristics of that gas to a NSW user. The final Rule should therefore avoid imposing physical tracing requirements in addition to certificate retirement.

3. What challenges or benefits could arise by allowing existing facilities to participate?

APGA supports the inclusion of existing facilities in the Scheme. Existing facilities will be able to provide a supply of Renewable Fuel Certificates (RFCs), which has the dual benefit of ensuring there are certificates available for Scheme participants to meet their obligations, and immediately provides liquidity to the market. There is no practical reason to exclude existing facilities where the Scheme may incentivise additional production.

4. What challenges could arise for early hydrogen producers making FID by 31 December 2026?

5. What other FID timeframe could capture early hydrogen producers?

6. What challenges could arise for early hydrogen producers starting by 30 June 2029?

7. What other production start timeframe could capture early hydrogen producers?

Achieving FID is a considerable project hurdle, and it is likely that the timeliness of the commencement of the Scheme will be a factor in those decisions. Given this, 31 December 2026 is may not a realistic deadline, especially for projects waiting to see the direction of a Federal policy.

At the same time, APGA appreciates the necessity of clearly delineating between Groups 1 and 2, where Group 1 will essentially be the test case that will then establish benchmarks for Group 2: the benefits of which this approach requires relatively strict temporal boundaries to recognise the risk of genuine early mover hydrogen projects.

The NSW Government should more broadly consider:

• · An eligibility threshold linked to the first tranche of eligible hydrogen production, rather than a fixed FID date. This would more directly target support to projects that establish the market, while avoiding a cut-off that may exclude genuine early movers because of project-specific development or commissioning timelines. Or;
• · Retain the 31 December 2026 deadline, with a review of Group 2 targets following Group 1.

APGA considers that the Scheme should permit, if not require, a review of Group 2 targets following Group 1 in any case, alongside provisions that regulate movement of obligations between groups where appropriate.

8. What challenges could arise for producers meeting the production emissions intensity for green hydrogen of 0.6 kg CO2-e per kg hydrogen?

Given the draft Rule specifies production pathways for green hydrogen, it is probably not necessary to additionally impose an emissions intensity threshold. Where producers also want to take advantage of the HPTI, that scheme’s 0.6 kg threshold will still apply. Otherwise, linked Product GO and RGGO certificates will necessarily limit the emissions intensity of the product.

APGA notes this intensity threshold is very low relative to international standards. The UK’s Low Carbon Hydrogen Standard threshold is 2.4 kg[1], the EU’s low carbon hydrogen threshold is 3 kg, and the US’s Clean Hydrogen Production Standard is 4 kg.

9. How practical are the purity and quality requirements for network-supplied and behind-the-meter renewable methane?

From a network perspective, the AS 4564 compliance requirement for renewable methane injected into the network is reasonable. AS 4564 was recently updated with precisely this use case considered. The 90% purity requirements for renewable methane behind-the-meter are also reasonable, and effectively matches biomethane specifications for non-biomethane sources of renewable methane.

APGA does have concerns about the inclusion of behind-the-meter (BTM) production into the Scheme more generally. BTM principally benefits the proponent, not the general market, which is largely the purpose of establishing tradeable RFS certificates as it incentivises additional production beyond what is necessary to decarbonise the proponent facility, allowing other NSW gas customers to access and benefit from this decarbonised gas.

10. How effective is inclusion of the four eligible production pathways for renewable methane in supporting commercial deployment and scale?

APGA generally does not think it necessary to prescribe specific pathways where there is also a purity/quality requirement, and where certification though other schemes (RGGOs and Product GOs) is required for RFS certification. As noted, RGGOs are technology-agnostic.

11. What other organic material could be considered an eligible feedstock?

APGA considers feedstock eligibility should align as far as practicable with the relevant renewable gas certification schemes. Where a feedstock and production pathway satisfy the sustainability, emissions and certification requirements of an approved certification framework, there is limited benefit in imposing a narrower feedstock restriction through the RFS itself. This would also reduce the risk of renewable methane being eligible for an RGGO or Product GO but ineligible for the RFS.

12. How effective is a 10-year eligibility period for landfill and sewage feedstocks in supporting commercial deployment and scale?

APGA appreciates the 10-year limitation is intended to reflect the “low-hanging-fruit” nature of landfill and wastewater renewable methane projects, and that the scheme must also support production methods that are currently higher-cost. There is a trade-off if uptake is slower than intended however, and there are a limited total number of landfill and wastewater projects.

APGA considers in light of this, the 10-year eligibility period is probably unnecessary. The projects that are ready to come to market will do so, and the remainder will be developed when it is economically feasible to do so, which may be longer than 10 years.

There is also a risk that, once the 10-year eligibility period expires, otherwise eligible renewable methane is diverted to alternative markets or uses. Where production continues to satisfy the Scheme's emissions, quality and certification requirements, excluding it solely because of the age or feedstock type of the project could reduce certificate supply without delivering a corresponding improvement in Scheme integrity.

13. What challenges could arise for producers meeting the production emissions intensity for renewable methane of 14.0 kg CO2-e per GJ renewable methane?

While APGA does consider this approach reasonable on the surface– i.e. the production emission intensity of renewable methane must not exceed those of the natural gas it is intended to replace – it is worth considering how this question is approached in the EU, where renewable methane is most advanced globally. The EU takes a reduction approach rather than specifying an emissions intensity, where renewable methane production must achieve a minimum 65% to 80% GHG reduction compared to fossil fuels.

14.0 kg emissions intensity threshold for renewable methane will be a considerable hurdle for many facilities, particularly anaerobic digesters where all emissions associated with feedstock aggregation, digestion and any energy requirements will fall within the “well-to-gate” production boundary.