Country
Assessment
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.