Methane Management Plans Under the Safeguard...

A coal mine reporting 80 kt of fugitive methane has 2.24 Mt CO2-e of Scope 1 emissions under NGER (AR5 GWP of 28). The same facility under AASB S2, applying the AR6 fossil methane GWP of 29.8, reports 2.384 Mt CO2-e. The Safeguard baseline declines 4.9% per year. The methane management plan now sits at the intersection of three frameworks that don't agree on the same number.

That's not a rounding problem. It's a governance problem. The auditor signing off on the AASB S2 disclosure is reading one number. The Clean Energy Regulator is reading another. And the board is trying to make a capex decision on a third — a forward trajectory that compounds the gap every year the baseline declines.

This is what a defensible methane management plan has to reconcile in 2026.

What the reformed Safeguard Mechanism actually requires

The Safeguard Mechanism covers facilities emitting more than 100,000 tonnes CO2-e of covered Scope 1 emissions in a financial year. After the 2023 reforms, baselines decline at a default rate of 4.9% per year through 2030, with post-2030 rates set in five-year periods aligned to the national NDC.

Facilities that exceed their baseline must surrender Australian Carbon Credit Units (ACCUs) or Safeguard Mechanism Credits (SMCs). Facilities that come in below their baseline can be issued SMCs. As of the most recent compliance year, 219 facilities held baselines, 62 received SMCs (8.3 million in total), and 7.1 million ACCUs plus 1.4 million SMCs were surrendered for compliance.

Methane is treated like any other Scope 1 source for compliance arithmetic. The underlying methodology determination is not. Five different chapters of the NGER (Measurement) Determination 2008 cover the five places fugitive methane shows up. Each comes with its own method tiers, its own measurement obligations, and its own room for the audit to land badly.

If a facility surrenders ACCUs equal to more than 30% of its baseline in a year, the operator must lodge a statement with the CER explaining why on-site abatement has not been undertaken instead. The credit market is not a quiet substitute for an abatement plan.

The five methane source categories and the methodology each one demands

The first job of a methane management plan is a source register. Not at the facility level. At the equipment, seam, and stream level. Each source maps to a different subdivision of the Measurement Determination.

Source	NGER methodology location	Highest method available
Underground coal mine gas and VAM	Chapter 2, Div 2.3.5	Method 2 or 3 (mine-specific)
Open-cut coal fugitives	Chapter 2, Div 3.2.3	Method 2 or 3 mandatory from FY27
Oil and gas operations (well to transmission)	Chapter 2, Div 2.3.6 and 2.3.7	Method 2 or 3
Landfill gas	Chapter 5, Div 5.3	Method 2 with measured capture
Wastewater treatment	Chapter 5, Div 5.5	Method 2 with site COD/BOD data

That is one defensible table per facility. Not one factor. The methane management plan has to set out, for every source, which method is being used, why, and what evidence supports it.

Method 1 versus the higher tiers

Method 1 uses default national emission factors. Method 2 calibrates measured data against those defaults. Method 3 builds factors entirely from site data under approved Australian or international standards.

For coal mining, the policy direction has already closed off the easy path. From 1 July 2025, open-cut mines covered by the Safeguard Mechanism that produced more than 10 million tonnes of coal in 2022-23 are required to use Method 2 or 3. From 1 July 2026, all open-cut Safeguard-covered mines must move to Method 2 or 3. Method 1 will not be a defensible choice for that cohort.

The reason matters. Method 1 for fugitive methane is built on national averages. Apply it to a gassy underground mine and it understates emissions. Apply it to a low-gas open-cut and it overstates them. Both errors flow through to the Safeguard baseline. A facility that has historically over-reported under Method 1 has a higher baseline than its measured emissions justify, which becomes an asset under a declining baseline. The opposite is also true. The methodology choice is not a technical detail. It's a balance sheet decision.

What a defensible methane management plan actually contains

A complete plan covers seven things. None of them are optional once the assurance engagement starts asking questions.

Source register. Every methane source at every facility, mapped to the relevant NGER subdivision, with the quantification approach for each.
Methodology selection rationale. Why Method 2 here, why Method 1 there, signed off by the responsible engineer.
Measurement and monitoring plan. Instrumentation list, calibration intervals, sampling frequency, chain of custody for laboratory analysis.
Abatement roadmap. What gets installed, when, at what capex, and what the modelled methane reduction is.
Baseline trajectory. The facility's Safeguard baseline year by year through 2030, with the abatement assumptions that close the gap.
ACCU and SMC position. Forecast surrender requirement, hedging strategy, and the section 73 trigger if surrender exceeds 30% of baseline.
Verification approach. How the operator will support an ASSA 5010 assurance engagement and a CER audit under section 73 of the NGER Act.

That document is read by four different audiences (operations, finance, the auditor, the CER) and needs to be the same document for all four. If it isn't, the version control problem becomes the audit finding.

The AR5 versus AR6 gap inside the plan

NGER currently uses AR5 GWP values. AASB S2 paragraph B19 requires the latest IPCC assessment, which is AR6. The values differ:

Fossil methane (coal, oil, gas operations): AR5 GWP 28, AR6 GWP 29.8. Difference: +6.4%
Biogenic methane (landfill, wastewater, livestock): AR5 GWP 28, AR6 GWP 27.0. Difference: −3.6%

A coal mine with 80 kt of methane reports 2.240 Mt CO2-e under NGER and 2.384 Mt CO2-e under AASB S2. A landfill with 10 kt of methane reports 280 kt CO2-e under NGER and 270 kt CO2-e under AASB S2. An integrated operator running both has to apply both GWPs to the same gas, depending on whether it came out of a coal seam or a decomposing waste cell.

We covered the mechanics in detail in the AR5/AR6 GWP reconciliation guide. The point for the methane management plan is that the gap can't be papered over with a reconciliation note at the end. The plan has to calculate both numbers from the same source data, document the GWP applied at each line, and explain the variance to whoever is signing the AASB S2 directors' statement.

Abatement options that map to ACCU methodologies

The Clean Energy Regulator publishes methodology determinations for projects that destroy or avoid methane. The map is moving and operators have to track it.

The Coal Mine Waste Gas method closed to new projects on 31 March 2025. Existing projects continue through their crediting period. New coal-mine methane abatement projects need to find a different route to credits, which for most operators means the project has to be justified on Safeguard compliance economics alone.

The Reducing Methane Emissions from Landfill Gas method 2025 replaced the previous landfill gas generation method (revoked 28 November 2025). It credits projects that destroy methane through flaring or electricity generation, upgrade biogas to biomethane, or refine biogas for combustion elsewhere. New and existing landfill operators need to assess whether their capture equipment qualifies under the new rules.

For oil and gas operators, the abatement options are leak detection and repair, vent reduction, flaring conversions, and electrification of compressor drives. None of these have a dedicated ACCU methodology — the abatement economics rely on Safeguard baseline compliance and (for some operators) voluntary commitments under the Global Methane Pledge framework Australia joined in October 2022.

For agriculture, manure management and herd genetics methods exist under the ACCU scheme but cover a small slice of national emissions.

The honest read: the ACCU market has been narrowed for methane projects, not broadened. The Safeguard baseline is now doing more of the work. That means on-site abatement capex sits inside the methane management plan, not outside it.

The audit perspective

ASSA 5010 assurance practitioners and CER auditors operating under section 73 of the NGER Act test the same documents from different angles. The methane management plan has to survive both.

The questions to expect:

Does the methodology selection rationale match the production data and gas content of the seam, well, cell, or pond?
Are calibration records continuous? Where are the gaps and how are they justified?
Is the aggregation arithmetic from source-level data to the disclosed total reproducible from source documents?
Where AR5 and AR6 numbers differ, is the GWP applied to each line traceable to the source register?
Is the abatement claimed in the forward trajectory additional? Does it double-count anything already credited under an ACCU project?

The eight checks we set out for ASSA 5010 preparation apply with extra force here, because methane is where the methodological judgement calls cluster.

The capital allocation arithmetic

A facility with a 2.0 Mt CO2-e baseline today, declining at 4.9% per year, has a baseline of approximately 1.22 Mt CO2-e by 2036. That's a 39% reduction obligation over a 10-year horizon, before any further tightening post-2030.

If methane is half of that facility's Scope 1 footprint and methane abatement options are limited, the compliance gap closes either through ACCU surrender (operating cost) or on-site capex (capital cost amortised over project life). The crossover point is sensitive to the ACCU spot price, the discount rate, and the residual abatement after the obvious projects are done.

The methane management plan needs to model that crossover. Not at annual budget time. At the multi-year capex planning horizon, because the equipment lead times and the regulatory approvals run two to four years. We've written separately about how Safeguard compliance tracking should sit inside the carbon ledger rather than in a separate spreadsheet, because the abatement modelling and the compliance position are the same data.

What this looks like as a working system

The methane management plan is a document. The data behind it is a system. The two have to match every quarter, not just at submission.

That means: per-source emissions data with methodology versioning attached, source-document attribution back to the field measurement or laboratory result, parallel AR5 and AR6 calculation runs from the same underlying activity data, an audit trail that survives a CER section 73 request without a forensic exercise, and a forward trajectory that updates when the abatement project schedule slips.

Carbonly's platform handles the per-source ledger, the parallel GWP calculations, the source-document attribution, and the report generators for both NGER and AASB S2 against the same data. The point is not the software. The point is that operators running this off spreadsheets in 2026 are signing themselves up for a reconciliation problem they don't have to have, against an audit standard that doesn't allow it.

What to do this quarter

If a methane management plan does not yet exist for a Safeguard-covered facility, the order of work is: source register first, methodology review second, AR5/AR6 reconciliation third, abatement roadmap fourth, forward trajectory last. Doing it in that order means the abatement roadmap is built on real numbers, not last year's NGER submission.

For a conversation about how the per-source ledger and AR5/AR6 parallel calculation work in practice, email hello@carbonly.ai or join the waitlist.

Methane Management Plans Under the Safeguard Mechanism: What Coal, Gas, Landfill and Agriculture Operators Need to Document