Australia’s flare gas volumes have been dramatically inconsistent since 2012, ranging between 0.7 and 1.4 billion cubic meters per year (figure 1). Flaring intensity follows this trend; Australia demonstrates average performance, having flared 6.21 cubic meters of gas per barrel of oil produced. Developments since 2019 indicate a sustainable downward trend in absolute volumes and flaring intensity. However, Australia’s flaring intensity is still higher than producers such as Canada, the United Kingdom, and the United States. This is partially explained by the fact that coal bed methane (CBM) operations, predominantly located in Queensland, involve a fair amount of flaring due to operational reasons.

Figure 2. Gas flaring volume and intensity in Australia, 2012–22 

Note: The flare data graphs in this report are based on global flaring data estimates of the Global Flaring and Methane Reduction (GFMR) Partnership using satellite data from the Colorado School of Mines. This approach is consistently applied to all countries covered in this report.

In June 2022, Australia submitted an updated Nationally Determined Contribution (NDC) to the United Nations Framework Convention on Climate Change (UNFCCC). The NDC’s unconditional target was to reduce greenhouse gas (GHG) emissions by 43 percent below 2005 levels by 2030. The country also reaffirmed its target to achieve net-zero emissions by 2050. In 2018, the Government of Western Australia endorsed the World Bank’s Zero Routine Flaring by 2030 initiative. 

Australia also participates in the Global Methane Initiative and the Global Methane Pledge.

At the national level, besides the NDC, no specific targets or limits exist for flared or vented volumes or methane emissions. Meanwhile, the Safeguard Mechanism  does include GHG emissions restrictions. The Safeguard Mechanism is the government policy for reducing emissions from Australia’s industrial facilities (including oil and gas production), which release more than 100,000 tonnes of carbon dioxide equivalent (tCO2e) per year. All new facilities are given a legislated baseline for total emissions, but no baseline is set for individual activities such as flaring. Facilities must purchase carbon credits if the cap is exceeded. Reforms introduced in mid-2023 will require baselines for new facilities to be set following international best practices, targeting an initial decline rate of 4.9 percent per year until 2030. Post-2030, decline rates will be set in “predictable five-year blocks” to achieve Australia’s NDC goals and net-zero emissions by 2050.

According to the Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019, “venting and flaring of natural gas should be eliminated or minimized where practicable.”

In New South Wales, flares must be operated efficiently and fugitive emissions minimized as per the Protection of the Environment Operations (POEO) Act, 1997.

In general, Australia’s regulatory approach targets environmental impacts and risks, including the reduction of GHG and other emissions to a level that is as low as reasonably practicable (ALARP) and acceptable. National or state regulators enforce compliance with requirements outlined in environment management, field development, or other plans for individual projects.

At the national level, the National Greenhouse and Energy Reporting (NGER) Act, 2007, enacted the Safeguard Mechanism, details of which can be found in the National Greenhouse and Energy Reporting (Safeguard Mechanism) Rule, 2015; Carbon Credits (Carbon Farming Initiative) Rule, 2015; and Australian National Registry of Emissions Units Regulation, 2011. The NGER Regulations, 2008, detail industries and activities that are subject to reporting obligations under the NGER Act, 2007.

The Offshore Petroleum and Greenhouse Gas Storage (OPGGS) Act, 2006, provides the regulatory framework for petroleum in Commonwealth waters and covers (1) exploration and recovery, and (2) injection and storage of GHGs. According to Part 6.1 of Volume II, holders of various petroleum and GHG permits must control the flow and prevent the escape of petroleum or GHG substances from production, processing, pipeline, and tank storage facilities during operations. Victoria’s OPGGS Act, 2010, has the same requirements, whereas Queensland has its own version of the GHG storage legislation: the Greenhouse Gas Storage Act, 2009.

The OPGGS (Environment) Regulations, 2009, require submitting an environment plan to the regulator (see section 6 of this chapter). According to Part 2 of the regulations, an environment plan must include descriptions of activities (location, construction, operations), a description of the environment, a demonstration of how legislative requirements applicable to the activities will be met, an assessment of environmental risks and mitigation measures, and an implementation strategy. According to Regulation 14, the implementation strategy must describe specific measures to reduce environmental impacts and risks to ALARP levels.

The key legislation in the Northern Territory is the Petroleum Act, 1984, and the Petroleum (Environment) Regulations, 2016. The Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019 —which is subject to the above two laws—addresses environmental risk and impact management and covers all upstream petroleum activities. Companies’ environment management plans must include a demonstration of how they plan to meet the code’s requirements. Part D of the code outlines methane emission monitoring, and leak detection, reporting, and management, besides including flaring and venting activities.

In Queensland, the Petroleum and Gas (Production and Safety) Act, 2004, bans the flaring or venting of petroleum gases unless authorized (see section 10 of this chapter). The Petroleum and Gas (Safety) Regulation, 2018, covers implementation. As per the Environmental Protection Act, 1994, a permit—known as an Environmental Authority—is required to undertake any oil and gas operation. The Greenhouse Gas Storage Act, 2009 , aims to reduce GHG emissions, primarily via geologic storage. The Code of Practice for Leak Detection, Management & Reporting for Petroleum Operating Plant, 2022, requires “operators to develop a process for the systematic monitoring and management of leakage to mitigate risks from gas leaks.”

In Victoria, the Petroleum Act, 1998, and the Petroleum Regulations, 2021, require maintaining emissions from leaks, flaring, or venting at an ALARP level. According to the OPGGS Regulations, 2021, an environment plan must describe how ALARP levels will be maintained and outline measures to identify and estimate emissions. Regulatory approvals must consider climate change impacts as per the Climate Change Act, 2017.

In Western Australia, the Petroleum and Geothermal Energy Resources (Environment) Regulations, 2012, address emissions and discharges from petroleum operations. The Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations, 2015, require operators to detail their management of flaring and venting in a field development plan (see section 11 of this chapter).

In New South Wales, the Petroleum (Onshore) Act, 1991, and Petroleum (Offshore) Act, 1982, (and the associated regulations) govern the licensing and regulation of petroleum activities onshore and in the state’s coastal waters, respectively. The POEO Act, 1997 , and its associated regulations govern emissions from all gas activities, including flaring and venting (Section 128). The POEO (Clean Air) Regulations, 2002, have specific guidelines on flaring and venting across industries, including petroleum refining and storage. The Environmental Planning and Assessment Act, 1979, and its associated regulations provide the framework for assessing petroleum projects before they are approved for development.

In South Australia, the Petroleum and Geothermal Energy Act, 2000, and its associated regulations govern onshore oil and gas operations, while the Petroleum (Submerged Lands) Act, 1982, governs operations in state waters. Although these laws and regulations mandate environmental impact assessments, the Environment Protection Act, 1993, governs emissions from oil and gas operations. These laws and regulations were found to have no specific guidelines for flaring, venting, and fugitive emissions, which are presumably covered under general environmental impact and risk assessment guidelines.

In Tasmania, the Mineral Exploration Code of Practice, 2012, governs oil and gas operations subject to the Mineral Resources Development Act, 1995, and other laws listed in the code. The code requires the elimination or reduction of environmental hazards “as far as practicable and according to good oilfield practice.” According to Section 32 of the code, a licensee must dispose of the produced oil and gas that is not gathered “in a manner that minimizes any environmental damage in accordance with good oilfield practice.”

The Australian government legislates and regulates petroleum operations in the Commonwealth waters, which the OPGGS Act defines as extending between 3 and 200 nautical miles off shore. States and territories legislate and regulate petroleum operations within their boundaries, including state waters, which extend up to three nautical miles off shore.

Oil and gas exploration and production activities in the Australian Commonwealth waters require the approval of the relevant joint authority and the independent regulator (see section 6 of this chapter). The Offshore Petroleum Joint Authority for each state or the Northern Territory comprises the Commonwealth minister and the minister of the relevant state/Northern Territory.

“The Australian Government and state and territory governments own Australia’s mineral and petroleum resources on behalf of the community.” The ownership of subsurface minerals is vested in the state under the mineral and petroleum legislation of states and territories, for example, Section 26(2) of Queensland’s Petroleum and Gas (Production and Safety) Act, 2004 , and Section 6(1) of New South Wales’ Petroleum (Onshore) Act, 1991 . The Australian government administers taxes and royalties for projects in the Commonwealth waters and some legacy onshore production (pre-1979 leases) in Western Australia.

At the national level, flaring and venting are regulated as part of GHG emission regulations. The Clean Energy Regulator (CER) is responsible for carbon abatement in Australia and administers the relevant laws, regulations, and programs (see section 7 of this case study). The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) regulates offshore oil and gas operations in the Commonwealth waters.

The Northern Territory’s Department of Environment, Parks and Water Security (DEPWS) administers the Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019 .

In Queensland, the Department of Resources administers the Petroleum and Gas (Production and Safety) Act, 2004 , which restricts flaring and venting. The Petroleum and Gas Inspectorate—part of the Resources Safety and Health Queensland (RSHQ), a statutory body established by the Resources Safety and Health Queensland Act, 2020—is the key regulator.

In Victoria, the Department of Energy, Environment and Climate Action (DEECA) regulates the oil and gas industry. Earth Resources, the former regulator, is now part of this department.

The Department of Mines, Industry Regulation and Safety (DMIRS) regulates the oil and gas industry in Western Australia. Companies must submit their environment and safety plans to DMIRS before oil and gas production can begin. 

In New South Wales, several agencies are responsible for regulating the gas industry. In 2015, the Environment Protection Authority, which issues environment protection licenses, was appointed as the lead regulator for all gas activities.

In South Australia, the Department of Energy and Mining, the Energy Resources Division, and the Environment Protection Authority coordinate responsibilities for regulating the oil and gas industry.

Mineral Resources Tasmania regulates activities in the minerals and petroleum industries, including environmental management. The Environment Protection Authority regulates the mining industry and underground oil storage but not the upstream exploration.

At the national level, the CER administers the Safeguard Mechanism , which caps total emissions from large oil and gas facilities (see section 2 of this case study), and the NGER framework, which covers the measurement and accounting of various emission sources, including flared or vented volumes, and fugitive emissions. The CER also administers renewable energy targets and the Emissions Reduction Fund.

NOPSEMA regulates the environmental as well as health, safety, and structural integrity provisions of the OPGGS Act . Each offshore oil and gas activity must have a NOPSEMA-approved environment plan, which must demonstrate that environmental impacts, including those associated with flaring, venting, and fugitive emissions, are reduced to an ALARP level and are acceptable. NOPSEMA accepts environment plans only if it determines that they meet the requirements of the OPGGS (Environment) Regulations, 2009 .

The National Offshore Petroleum Titles Administrator (NOPTA) is responsible for “assisting and advising the Joint Authority and the responsible Commonwealth Minister” and managing data and title registers.

The Northern Territory’s DEPWS, established in September 2020, assumed the functions of the previous Department of Environment and Natural Resources, including regulating petroleum operations and their environmental impacts.

In Queensland, the Department of Resources administers the Petroleum and Gas (Production and Safety) Act, 2004 . Meanwhile, the Department of Environment and Science issues the Environmental Authority  after evaluating the environmental impact statement, which is either mandatory or voluntary, as outlined in the Environmental Protection Act, 1994 .

In New South Wales, the Environment Protection Authority is the lead regulator for all onshore petroleum exploration and production activities and is responsible for all compliance and enforcement activities under the Petroleum (Onshore) Act, 1991 , except for work health and safety, which is regulated by the Resources Regulator (formerly the Division of Resources and Energy within the Department of Industry). The Resources Regulator and the Environment Protection Authority collaborate when engineering standards designed for human safety contribute to environmental performance. The Department of Planning and Environment issues development consents. A memorandum of understanding outlines how different agencies collaborate to regulate the gas industry while avoiding duplication.

In South Australia, the Department of Energy and Mining’s Energy Resources Division has an administrative arrangement with the Environment Protection Authority to coordinate responsibilities for regulating the oil and gas industry.

As per the OPGGS Act , NOPSEMA undertakes inspections and investigations and can enforce injunctions and civil penalties. In particular, NOPSEMA conducts compliance-monitoring activities to assess whether an operator is fulfilling the commitments under an accepted environment plan. The environment plan may include various control measures in relation to flaring, venting, and fugitive emissions. Such measures may include, for example, leak detection and repair (LDAR) programs and procedures in case of safety or emergency incidents. The focus of NOPSEMA’s inspections is to ensure the implementation of these measures and their improvement over time.

In Queensland, the Petroleum & Gas Inspectorate conducts inspections, audits, and investigations at facilities across the natural gas supply chain. These activities are conducted as per the Petroleum and Gas (Safety) Regulation, 2018 , and cover all facilities across this supply chain, from production sites to distribution networks.

In Western Australia, DMIRS inspectors can inspect petroleum facilities, interview people, and gather evidence to ensure compliance with regulations and submitted environment and safety plans.

In New South Wales, coal seam gas and petroleum operators seeking to obtain the environment protection license mandated by the Environment Protection Authority must demonstrate that they have taken measures to minimize fugitive emissions through continuous monitoring, LDAR programs, and various assessments. Schedule 2A of the POEO Act  enables the Environment Protection Authority to enforce compliance with environmental laws and license conditions and issue formal warnings, clean-up and prevention notices, penalty notices, and legally binding pollution reduction programs in case of noncompliance. For serious matters, the Environment Protection Authority can also pursue prosecution.

In South Australia, the regulatory approach is similar to that of New South Wales. The Energy Resources Division pursues a monitoring and compliance policy based on the enforcement pyramid, which correlates the severity of enforcement actions with offenses. According to the Petroleum and Geothermal Energy Act, 2000 , the regulated entity, not the regulator, has the primary responsibility for detecting and rectifying noncompliance. The Environment Protection Authority follows a similar approach to monitoring and compliance. The approach ties compliance actions to the seriousness of impacts and the significance of risks.

For exploration activity to commence, Mineral Resources Tasmania must approve work programs after a site inspection.

No explicit statements on flaring and venting without prior approval were identified in the documents consulted. Section 10 of this case study addresses the regulatory approach at the national and state levels.

For the environment plan to be approved by NOPSEMA, operators must demonstrate that emission levels are ALARP and acceptable. NOPSEMA does not prohibit or set limits on flaring or venting, or set methane intensity; instead, it pursues an “outcome-based” regulation. NOPSEMA will reject an environment plan if it does not find emission reduction levels to be ALARP and acceptable.

According to the Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019 , Reduced Emissions Completions (RECs) are required where it is technically feasible to capture gas for sale or use. If RECs are not practicable, flaring must be used instead of venting, which is allowed only if capture or flaring is impossible.

In Queensland, according to the Petroleum and Gas (Production and Safety) Act, 2004 , gas flaring is authorized if it is not feasible to use the gas commercially or technically, and venting is authorized if the gas is not safe to use or flare, or flaring is not technically practicable. For petroleum lease holders, venting is also authorized if it is part of a GHG abatement scheme.

No similar flaring- or venting-specific guidelines were found in the legal and regulatory documents of other states, whose regulatory approach follows the ALARP principle and aligns with the national approach.

The OPGGS (Resource Management and Administration) Regulations, 2011, require field development plans. However, the section on the content of the field development plan (Regulation 4.07) is not explicit regarding flaring, venting, or methane emissions, Regulation 7.19 requires petroleum production licensees to include “gaseous petroleum flared or vented” in their monthly production report. Also, Regulation 4.14 requires “details of any proposed disposal or flaring of any produced hydrocarbons” in an application to recover petroleum before the acceptance of a field development plan. This suggests that the plans will likely include flaring details.

Victoria’s OPGGS Regulations, 2021 , include the same requirements as Regulations 7.19 and 4.14. In addition, Victoria’s Petroleum Act, 1998 , requires a petroleum production development plan (Division 6). NOPTA reviews field development plans.

Regulation 4.18 of the OPGGS (Resource Management and Administration) Regulations, 2011, requires operators to submit to NOPTA a rate of recovery application, which must be supported by “evidence that the equipment and procedures used to determine the quantity and composition of petroleum and water have been approved.” The submission on equipment and procedures should describe the metering of flaring and additional discharge (if any) within the processing facility. If the Offshore Petroleum (Royalty) Act, 2006, applies, the equipment and procedures application should be submitted to Western Australia’s DMIRS. Once this is approved, the rate of recovery application can be submitted to NOPTA.

Part D.5.1 of the Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019 , requires a Methane Emissions Management Plan (MEMP), which demonstrates operators’ plans to reduce emissions to a level that is ALARP and acceptable through active monitoring and management. The MEMP must contain the practices followed for selecting equipment, designing standards, and maintaining equipment; the methodology and frequency of monitoring; leak classification and response; and emissions reporting.

In Queensland, the Code of Practice for Leak Detection, Management & Reporting for Petroleum Operating Plant, 2022 , requires operators to develop a leak management plan to ensure leaks from wells, gathering systems, and processing facilities are detected, classified, controlled, and reported.

In Western Australia, Part 6 of the Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations, 2015 , requires a field management plan (FMP) for petroleum recovery. The FMP must include detailed arrangements for petroleum disposal, venting, or flaring during production operations (Schedule 3) and must be consistent with the environment plan. The DMIRS must approve the FMP before production can begin. Regulation 58 requires submitting “details of any proposed disposal or flaring of produced petroleum” in an application to recover petroleum before the acceptance of an FMP. Part 3 of the regulations also requires a well management plan, which demonstrates that the risks of well activities will be ALARP, including those associated with flaring.

In South Australia, the Petroleum and Geothermal Energy Act, 2000 , requires work programs to be submitted as part of the application for exploration, retention, and production licenses. There are no specific instructions concerning flaring, venting, or methane emissions, but “sound production practice” is expected for a royalty waiver, and the minister may consider variations to the work plan before approving it.

In Tasmania, the Mineral Exploration Code of Practice, 2012, requires work programs to include details on potential environmental impacts and mitigation measures.

In New South Wales, under the Petroleum (Onshore) Act, 1991 , the beneficial use of gas may be permitted under a petroleum operations title only if that gas would otherwise have been flared or vented as part of licensed operations (Section 28B).

Similar language was not found in the laws and regulations of the other jurisdictions consulted. However, there are frequent references to good or sound oilfield practices and optimum recovery of resources.

At the national level, GHG emissions, including those associated with flaring and venting, and fugitive emissions from oil and gas operations, are measured according to NGER (Measurement) Determination, 2008, which the CER administers. Emissions measurement follows four general principles: transparency, comparability, accuracy, and completeness (Section 1.13). Several methods are described; those applicable to oil and gas operations are discussed in section 15 of this case study.

The environment plan required by the OPGGS (Environment) Regulations, 2009 , must provide for “appropriate environmental performance outcomes, environmental performance standards, and measurement criteria” (Regulation 10A[d]) and include “an appropriate implementation strategy and monitoring, recording and reporting arrangements” (Regulation 10A[e]). Regulation 14 states that the titleholder must report to NOPSEMA on its environmental performance at least annually according to the accepted environment plan. Part 3 details reporting and recordkeeping requirements and noncompliance penalties.

According to the Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019 , emissions associated with flaring and venting during flowback and workovers must be measured—using methods consistent with NGER (Measurement) Determination, 2008—and reported. Part D.4 of the Code of Practice requires three types of regional methane monitoring programs. The first of these are baseline methane assessments, which are required to identify major methane sources before a proposed upstream oil and gas activity. These baseline studies should include measurement of carbon dioxide, oxides of nitrogen, and particulate matter before and after gas production starts. During the baseline study, fixed monitoring stations may be installed for routine monitoring after gas production begins.

The second type are regional methane assessment programs, which are required to characterize the existing natural and anthropogenic sources of methane emissions in a license area and in adjacent areas before exploration activity begins and immediately after full-scale production starts. Three assessments are required for exploration or production with hydraulic fracturing. The emissions may be estimated or directly measured.

The third type are routine periodic atmospheric monitoring programs, which are required every five years to detect any changes in methane emissions during the life of a producing asset. Fixed atmospheric monitoring stations must be established at least a year before gas production begins. According to the Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019, “The number and location of monitoring sites must be sufficient to demonstrate shale production activities have not resulted in a regional enrichment of methane (and where relevant other GHG and particulate matter) above the background.” If significantly higher methane levels are detected, operators are required to identify the source and repair any leaks. A report must be submitted within a month of detection.

In Queensland, according to the Petroleum and Gas (Production and Safety) Act, 2004 , a producer must measure volumes flared or vented (Section 801). The measurement must be with a meter—chapter 8 of the act details petroleum and fuel gas measurement schemes and meter criteria. The contents of a measurement scheme for metering include identifying each meter (by type), applicable Australian or other standards, testing methods and frequency, maintenance procedures, and other specifications (Section 637). Annual measurement reports are required (Section 650).

The Code of Practice for Leak Detection, Management & Reporting for Petroleum Operating Plant, 2022 , requires operators in Queensland to conduct routine visits to well sites, gathering systems, and processing facilities to inspect for leaks and ensure compliance with a leak management plan. Leaks from the surface equipment at a petroleum well and in gathering systems must be reported to the Petroleum and Gas Inspectorate within five days of detection.

According to Petroleum Regulations, 2021 , operators in Victoria must submit an annual report, which should include “a summary of actions taken to monitor, measure, eliminate or minimize” emissions from leaks, flaring, or venting during petroleum operations based on the ALARP criteria.

In Western Australia, as per the Petroleum and Geothermal Energy Resources (Resource Management and Administration) Regulations, 2015 , companies must submit to DMIRS daily drilling reports, monthly production reports, and reports upon well completion. Volumes of gaseous petroleum (flared or vented) should be included in annual assessment reports (Schedule 2) and monthly production reports (Schedule 17). Regulation 34 of the Petroleum and Geothermal Energy Resources (Environment) Regulations, 2012 , requires operators to monitor and report emissions and discharges every three months.

In New South Wales, all petroleum operations require an environmental protection license, which mandates reporting land, noise, air, and water monitoring data as specified in each license. In South Australia, the Environment Protection Act, 1993 , mandates regularly reporting environmental quality and compliance with statutory requirements. No specific instructions on flaring, venting, or methane emissions were found in the legal and regulatory documents consulted for either state.

In Tasmania, the Mineral Exploration Code of Practice, 2012, requires licensees to ensure systems are implemented to control environmental, health, and safety hazards, and detect and respond to emergencies. Systems must be continuously improved via regular audits and reviews.

At the national level, no evidence specific to flaring, venting, or methane methods and measurement frequency could be found in the sources consulted. Regulation 14 of the OPGGS (Environment) Regulations, 2009 , requires that the environment plan implementation strategy “provide for sufficient monitoring, recording, audit, management of nonconformance and review of the titleholder’s environmental performance.”

Part D.5.1 of the Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019 , requires routine inspections for the detection of fugitive methane emissions by “properly trained and competency-assured” personnel using calibrated gas detectors. Compressor stations and pneumatic devices must be inspected every quarter, well pad equipment biannually, and all other facilities annually. Inspection after major maintenance must be conducted within 48 hours of restart. If optical gas imaging equipment is used, an annual inspection as per the United States Environmental Protection Agency (US EPA) Method 21 must be performed.

In Queensland, the Code of Practice for Leak Detection, Management & Reporting for Petroleum Operating Plant, 2022 , requires operators to conduct leak surveys at least every five years. Still, the frequency depends on multiple factors, including age of the facility or equipment, characteristics of petroleum, facilities’ design, and proximity to other infrastructure. Surveys must be “conducted by trained personnel using industry-accepted gas detection instruments calibrated in accordance with the manufacturer’s requirements.”

In Western Australia, according to Regulation 34 of the Petroleum and Geothermal Energy Resources (Environment) Regulations, 2012 , emissions and discharges can be monitored and reported either continuously or at specific intervals as outlined in the environment plan. Operators are responsible for testing the monitoring equipment to ensure accuracy.

NGER (Measurement) Determination, 2008, establishes calculation methods and prescribes specific methods for various sources of GHG emissions, including those associated with flaring and venting, and fugitive emissions at oil and gas facilities. Engineering formulas are based on emission factors, fuel composition shares, destruction efficiency of fuel type, and other inputs. For oil or gas exploration and development, Subdivision 3.3.2.2 provides three emission estimation methods (formulas)—one with a variant, for emissions from flaring, depending on whether carbon dioxide, methane, or nitrous oxide is released. Subdivision 3.3.2.3 provides methods for estimating fugitive emissions from process vents, system upsets, and accidents. Similarly, Division 3.3.3 provides a detailed assignment of different methods for estimating emissions from flaring and fugitive methane emissions during crude oil production; Division 3.3.4 provides the same for crude oil transport; Division 3.3.5 provides the same for crude oil refining; and several other divisions provide methods for estimating fugitive emissions from the natural gas supply chain. 

Regulation 14 of the OPGGS (Environment) Regulations, 2009 , requires titleholders to maintain “a quantitative record of emissions and discharges (whether occurring during normal operations or otherwise).” This record is used to assess whether the environmental performance outcomes and standards outlined in the environment plan are achieved and met. According to Regulation 27 (Storage of Records), a titleholder must store the environment plan and associated reports (monitoring, audit, review), and records (detailing emissions and discharges, calibration and maintenance of monitoring devices) “in a way that makes retrieval of the environment plan reasonably practicable.” Regulation 28 outlines the titleholder’s responsibility for making records available when requested by NOPSEMA or its inspectors.

The Code of Practice: Onshore Petroleum Activities in the Northern Territory, 2019 , follows the requirements of the Petroleum (Environment) Regulations, 2016 , on recording, monitoring, and reporting (Schedule 1, clause 11). In particular, the code requires maintaining inspection reports and keeping maintenance records, besides recording the volumes associated with leaks and vents and including them in mandatory reports (see section 13 of this chapter).

In Queensland, measurement schemes required by the Petroleum and Gas (Production and Safety) Act, 2004 , must include a description of the records to be maintained and the minimum period for which they will be kept. Such records may include anomalies, complaints, and actions to be rectified. Records associated with the safety management system are kept for seven years (Section 678A).

In New South Wales, the POEO Act, 1997 , empowers regulators to require records (Part 7.3) as part of their investigation powers. These requirements apply to all regulated activities and are not specific to flaring, venting, or methane emissions.

In Victoria, operations must maintain “quantitative records of emissions and discharges into the air… that can be monitored and audited against environmental performance standards” (Section 33 of Petroleum Regulations, 2021; see footnote 22).

In South Australia, the Environment Protection Act, 1993 , requires “the maintenance of a record of trends in environmental quality,” which can be used to ensure compliance with environmental requirements.

In Tasmania, the Mineral Exploration Code of Practice, 2012, requires licensees to document their systems for controlling or detecting environmental, health, and safety hazards. These documents must be retained for inspection purposes.

GHG emissions data collected under the NGER are used to develop Australia’s national GHG inventory and comply with the UNFCCC’s reporting requirements.

The results from the fixed monitoring stations for routine periodic atmospheric monitoring programs (see section 13 of this chapter) must be made publicly available via the Northern Territory Government portal.

In New South Wales, the Environment Protection Authority’s public register has all data required by environmental protection licenses.

There are civil penalties for noncompliance with the requirements of the OPGGS Act  and the associated regulations. For example, a titleholder undertaking an activity without an environment plan is fined 80 penalty units. Similarly, 30- to 80-penalty-unit fines are imposed for not complying with the environment plan, not reporting incidents, not storing records per regulations, and other violations of the OPGGS (Environment) Regulations, 2009 . Violations of the field development plan provisions of the OPGGS (Resource Management and Administration) Regulations, 2011, can attract a 60- to 80-penalty-unit fine.

These penalties are enforceable under Part 4 of the Regulator Powers (Standard Provisions) Act, 2014. A penalty unit is currently set at $A 275 in the latest version of the Crimes Act, 1914. (Please note that Australia’s jurisdictions have assigned penalty units at different amounts.)

In Queensland, according to the Petroleum and Gas (Production and Safety) Act, 2004 , operators are fined 500 penalty units for noncompliance with measurement obligations, including the measurement of any flared or vented petroleum (Section 801). In chapter 8, specific penalties ranging from 100 to 500 penalty units are assigned for noncompliance with various measurement requirements and regulatory notices. The penalty unit is set based on the Penalties and Sentences Act, 1992, and was increased to $A 154.80 as of July 2023.

In Western Australia, the Petroleum and Geothermal Energy Resources (Environment) Regulations, 2012 , specifies a penalty of $A 10,000 for noncompliance with the environmental plan requirements (Part 2) and $A 5,500 for noncompliance with monitoring and reporting requirements (Regulation 34).

In New South Wales, penalties can be imposed under various legislation governing the petroleum sector. These are referenced in Schedule 2A of the POEO Act . According to Section 78A of the Petroleum (Onshore) Act, 1991 , breach of environmental requirements can attract a 10,000-penalty-unit fine for corporations and a 2,000-penalty-unit fine for natural persons, with a 10 percent additional penalty for each day of continuing offense. In the latest edition of New South Wales’ Crimes (Sentencing Procedure) Act, 1999, the penalty unit is $A 110.

In Victoria, noncompliance with various requirements of the petroleum production development plan attracts a 240-penalty-unit fine, according to Division 6 of the Petroleum Act, 1998 . As of July 2023, the penalty unit is $A 192.31.

In South Australia, Part 11 of the Environment Protection Act, 1993 , allows the Environment Protection Authority to impose civil penalties. Under Part 12 (Environment Protection) of the Petroleum and Geothermal Energy Act, 2000 , a penalty of $A 120,000 is imposed for noncompliance with environmental requirements.

No evidence of nonmonetary penalties for violating flaring-, venting-, or methane-emission-related requirements were found in the sources consulted. However, many Australian regulators pursue a gradual compliance enforcement program, which includes prosecution for severe offenses. For examples, see the links for New South Wales’ and South Australia’s regulatory approaches in section 8 of this case study.

No evidence of specific performance requirements for flaring, venting, and methane emissions was found in the sources consulted. Most regulators, including NOPSEMA, the Northern Territory’s DEPWS, Victoria’s DEECA, and Western Australia’s DMIRS, require an environment plan for each proposed petroleum activity, the plan necessarily demonstrating reduction of emissions or environmental impacts and risks to levels that are ALARP or acceptable.

According to Section 10 of the Offshore Petroleum (Royalty) Act, 2006, royalty is not payable if the Western Australia state minister “is satisfied that the petroleum has been flared or vented in connection with operations for the recovery of petroleum” and flaring and venting did not contravene the OPGGS Act, 2006 , and associated regulations.

In Queensland, according to the Petroleum and Gas (Production and Safety) Act, 2004 , an operator is exempt from paying petroleum royalty if the revenue commissioner is satisfied that the volumes flared or vented were part of exploration drilling (Section 591). The exemption applies to gas flared or vented during the production testing period but only up to 3 million cubic meters (Section 591A). As per Section 926, petroleum royalty is not payable for volumes flared or vented if approval was given under the Petroleum Act, 1923, before December 31, 2004.

In Western Australia, according to the Petroleum and Geothermal Energy Resources Act, 1967, and the Petroleum (Submerged Lands) Act, 1982 , operators may apply to the DMIRS for exemption from royalty payment for petroleum that—with the minister’s approval—is flared or vented in connection with petroleum recovery operations.

Under New South Wales’ Petroleum (Onshore) Act, 1991 , royalty is not payable if the minister approves gas flaring or venting (including of gas or other forms) for operations connected with petroleum recovery (Section 87).

In South Australia, according to the Petroleum and Geothermal Energy Act, 2000 , royalty is not payable if petroleum or any associated substance is “destroyed or dissipated in accordance with sound production practice” (Part 7).

In Tasmania, security deposits are required and must be high enough to cover environmental liability.

The Carbon Credits (Carbon Farming Initiative) Act, 2011, made GHG emissions reduction possible for crediting companies across the economy. The Carbon Farming Initiative Amendment Act, 2014, established the Emissions Reduction Fund, which is administered by CER and is now known as the Australian Carbon Credit Unit (ACCU) Scheme. Companies can earn ACCUs for reducing fugitive leak and venting emissions at oil and gas extraction, production, transport, and processing facilities by installing and operating equipment to capture these gases and combusting them in a flare device. The Carbon Credits (Carbon Farming Initiative—Oil and Gas Fugitives) Methodology Determination, 2015, establishes “procedures for estimating abatement (emissions reduction and sequestration) from eligible projects, and rules for monitoring, record keeping and reporting.”

No evidence of negotiated agreements between the public and private sectors was found in the documents consulted.

Generally, laws and regulations governing GHG emissions also apply to midstream and downstream activities. For example, Part 9.11 of Volume II of the OPGGS Act  provides regulations for preventing petroleum’s wastage or its escape from pipelines conveying it to be flared or vented (see section 3 of this case study for other examples).

As discussed in section 15 of this case study, the NGER (Measurement) Determination, 2008, establishes calculation methods and prescribes specific methods for various sources of GHG emissions, including those associated with flaring and venting, and fugitive emissions across the oil and gas midstream and downstream activities.

Some states have separate laws and regulations for pipelines, storage facilities, processing plants, refining facilities, and distribution networks, but the requirements appear to be mostly consistent with national GHG emission restrictions.