A2EP calls for an equal playing field in response to the National Renewable Gas Policy consultation paper
Australia should assess all low-carbon fuels equally, with the same ruler and the same criteria. That was the central message of A2EP's submission to the federal Department of Climate Change, Energy, the Environment and Water's National Renewable Gas Policy Consultation Paper, lodged on 9 October 2026.
A2EP strongly supports a national renewable gas policy and agrees biomethane should be its near-term focus. But we argue biomethane should be treated as a strategic national opportunity, not a niche decarbonisation option, and that current national support settings work against it.
Australia's natural advantage
Relative to its population and its own gas demand, Australia's recoverable biomethane resource appears to be the largest of any economy we compared. Around 400 PJ a year is considered recoverable today, or about 15 GJ per person. That compares with roughly 11 GJ in the United States, 7 GJ in Germany and around 1 GJ in Japan and Korea (two of our largest LNG customers).
Measured against domestic gas use, the gap is even more stark: biomethane could in principle meet around 45% of Australia's domestic gas demand, compared with 2% to 4% in Japan and Korea.
Germany shows what policy can do. It already produces around 400 PJ of biogas a year, comparable to Australia's entire recoverable resource, built largely on two decades of feed-in support. Australia is one of very few developed economies that could both decarbonise a material share of its own gas use and, in time, supply renewable methane to energy-importing partners.
These cross-country comparisons are indicative, because different studies use different methods, years and feedstock boundaries. The direction, however, is robust.
The foundations are here, the frameworks are not
Australia already has most of the hard-to-replicate foundations of a biomethane industry: large volumes of agricultural residues, food and organic wastes, an extensive gas network now covered by an Australian Standard for biomethane, industrial and commercial customers, and NGER recognition of biomethane since July 2025. Anaerobic digestion and upgrading are mature technologies, with thousands of plants operating in Europe.
What is missing are the frameworks that turn those foundations into investable biomethane projects. There is no national production incentive and no binding demand signal. Digestate is still treated as a waste in most jurisdictions, approvals are inconsistent, and almost all core equipment is imported. Australia has only one operating injection plant at Malabar, NSW, so lenders have little local cost and performance data to price risk.
A2EP's submission highlights the importance on acting soon to capitalise on our natural advantages. AEMO forecasts east coast gas shortfalls from 2029. The Large-scale Renewable Energy Target ends in 2030, removing certificate revenue from more than 80 landfill gas sites that are among the cheapest near-term sources of biomethane. Without a framework in place before then, some of that supply may simply be flared.
An uneven playing field
Current national support for low-emission fuels is markedly uneven, and biomethane receives nothing.
Fuel | Main national incentive | Approx. value (A$/GJ) |
Renewable hydrogen | Hydrogen Production Tax Incentive, plus Hydrogen Headstart | ~14–17 |
Domestic biodiesel | Concessional fuel excise rate | ~10 |
Renewable diesel and SAF | A$1.1 billion Cleaner Fuels Program, plus a 2026–27 Budget demand measure | Rate not yet published |
Biomethane | No production incentive or demand measure | 0 |
To put that in context, the hydrogen incentive alone is about the size of the entire wholesale price of east coast gas. A biomethane developer competing for the same investors, offtakers, engineering capacity and, in some cases, feedstock starts the race A$10 to $17/GJ behind.
The disparity grows when measured against the support each fuel needs to reach price parity with the fuel it replaces. On A2EP's assumptions, closing the renewable diesel gap costs roughly A$1,400 to $1,800 per tonne CO2-e, against roughly A$100 to $270 for biomethane. Yet it is renewable diesel, not biomethane, that has a dedicated national production program.
Capital and feedstocks follow the policy signal. Where fuels compete for the same inputs, an incentive for one lets its producers outbid the others regardless of which delivers the most abatement. Within bioenergy, biogas burnt for electricity earns certificates until 2030, while the same biogas upgraded to displace fossil gas earns nothing.
One ruler for every fuel
A2EP's submission does not ask government to pick biomethane. We're asking it to stop picking against it. The Consultation Paper itself lists technology neutrality, focusing on outcomes rather than prescribing a single technology, as a potential policy objective. We strongly support that principle and ask that it be applied consistently across all low-emission fuels, not only within renewable gas. In practice, that means one test for every fuel:
emissions abated, on a lifecycle basis
cost per tonne of abatement
volume deliverable before the east coast supply gap opens in 2029
If hydrogen or e-methane pass that test, they should receive the same support. That's what technology neutral actually means. On these measures biomethane compares strongly: it is commercially mature, works as a drop-in fuel in existing networks and equipment, and can contribute to domestic supply this decade. Much of its feedstock, such as manures, food waste and wastewater, isn't suitable for liquid fuel pathways, so it often doesn't compete for inputs at all.
Biomethane is also a platform for later fuels rather than a competitor to them. Upgrading biogas produces a concentrated stream of biogenic CO2, in the order of 10 Mt to 15 Mt a year at full resource, which is the carbon source needed for e-methane and power-to-liquid sustainable aviation fuel.
Build early demand on ability to pay
A2EP does not support restricting renewable gas to "hard-to-abate" users in the early years. The users most often given that label, such as steel, cement, glass and bricks, typically buy energy at or below around A$10/GJ and energy is a large share of their costs. They face the widest gap to biomethane and have the least capacity to absorb a premium.
The buyers who can pay a premium today are those for whom gas is a small share of total costs, such as offices, hotels, hospitals and aged care. Commercial buildings used 45.8 PJ of gas in FY2024, about 9% of domestic consumption. For many of these buildings, retrofit electrification is rarely undertaken and frequently uneconomic, while certified biomethane needs no new equipment at all.
Letting those buyers fund the first wave of projects builds the scale that drives costs down. That cost reduction, not a reservation of scarce early supply, is what will ultimately make biomethane affordable for hard-to-abate industry. A2EP recommends a review at around five years to confirm those users can access supply at workable prices.
A2EP's recommendations
Our submission sets out 10 recommendations (designed to work as a package) and scores 13 policy measures for their expected impact on renewable gas uptake. The key recommendations are:
Recognise biomethane as a strategic national opportunity for energy security, industrial competitiveness, regional development and, in time, exports.
Make the policy outcomes-based and technology-neutral in practice, with competitive neutrality between fuels as an explicit principle.
Introduce a biomethane production incentive, ideally by extending the Hydrogen Production Tax Incentive framework, for 10 or more years.
Support a Domestic Supply Obligation renewable gas premium for new biomethane, with no end-use restrictions at the outset.
Build early demand around ability to pay, backed by an aspirational national production target open to any gas meeting an emissions threshold.
Establish a dedicated, time-limited deployment round through ARENA and the CEFC, plus long-term offtake underwriting.
Regulate digestate on product quality, not origin, and settle the accounting treatment of biogenic CO2.
Build the domestic supply chain and workforce for digesters, upgrading and injection equipment.
Fix near-term infrastructure barriers, including shared costs for compression and reverse flow and a consistent approvals pathway.
Develop an export framework now, starting with certificate recognition with Japan, Korea and other partners.
With policy settled in 2027, A2EP considers the first tranche of commercial-scale plants could be operating by 2029-30, provided approvals, connection and offtake barriers are addressed in parallel.
