Country
Assessment
Under Chapter 5 of the Energy Act, 2016 , nonmonetary penalties can increase in severity if, for example: an enforcement notice informs an operator of its failure to comply with a petroleum-related requirement and may include directions for compliance (Section 43) a revocation notice declares that the license will be revoked by a certain date for failure to comply with a license requirement (Section 47) an operator removal notice announces the date of removal of an operator that had failed to comply with a license requirement (Section 48). The OGA follows a “measured escalation” process before deciding whether to pursue sanctions. Before pursuing sanctions for violations, the OGA may require regulatory compliance plans and more frequent reporting of, for example, volumes of gas flared. The OGA requires that operators conduct ”lessons learned exercises” following consent breaches to avoid similar breaches in the future. As part of the OGA’s progressively more proactive approach to using its powers in the future, the OGA Flaring and Venting Guidance, 2021 , suggests a more stringent approach than in the past to sanctions in case of failure to comply with flare or vent consents. OPRED also has enforcement powers associated with its environmental regulation of offshore oil and gas operations. Although the specifics may change according to individual regulations, inspectors from the Offshore Environmental Inspectorate can board offshore installations with any equipment necessary to conduct investigations into compliance, interview staff, and collect relevant data. If inspectors find noncompliance, enforcement actions can range from written notices to operators to ensure compliance for relatively minor violations to civil sanctions, revocation of permits, and prosecution for more serious or persistent noncompliance. Enforcement must be proportional to the violation, related to specific violations, consistent, transparent, and accountable.
Specific performance requirements on flaring or venting could not be identified in the official documents reviewed. The OGA implemented a benchmarking process based on the flaring and venting data it started collecting in July 2017. The data can be used to identify facilities that are performing worse than the industry average. The OGA anticipates that this benchmarking exercise will allow operators to learn best practices from others and to help them reduce their flaring and venting as well as overall emissions at the least cost. The OGA has had success with benchmarking in raising performance levels in production efficiency, unit operating costs, recovery factor, and decommissioning.
There is no carbon tax on GHG emissions associated with oil and gas activities, but emissions are covered under the UK ETS regime. There is a climate change levy on electricity, gas, liquefied petroleum gas, and other energy sources derived from fossil fuels at the end-user level. In 2016, the petroleum revenue tax was permanently eliminated; before the reform, it had been 50 percent. The supplementary charge was reduced to 10 percent, down from 20 percent under the Corporation Tax Act, 2010. These fiscal reforms were intended to facilitate MER UK. Despite industry expectations, the government did not offer any fiscal incentives for investments to mitigate environmental impacts, including flaring and venting.
All UKCS oil and gas facilities have been subject to EU ETS requirements. Following Annex I of the EU ETS Directive 2003/87/EC, 2003 , these requirements cover offshore installations that emit carbon dioxide from combustion installations with a maximum thermal input exceeding 20 megawatts, including flares. Operations were provided free allocations if their compliance with the EU ETS put them at a competitive disadvantage in the global market (that is, if they were not able to reflect the cost of compliance in the price of their goods and services and lost market share as a result), a situation known as carbon leakage. As such, the EU ETS did not affect GHG emissions from flaring or most other oil and gas industry activities until recently. In 2021, Phase IV of the EU ETS started. The changes in Phase IV exclude installations associated with gas extraction, including flaring, from the carbon leakage list. Accordingly, flare installations will receive only 30 percent of their emissions allocations free until 2026, after which the free allocation will decline to 0 percent by 2030. The United Kingdom played an integral role in the development of Phase IV, and the UK ETS is expected to follow the EU ETS closely. However, the cap is 5 percent lower than the United Kingdom’s share of Phase IV cap to support the net-zero target of the government. It is also possible that the two trading schemes will be linked in the future, although changes to the way the United Kingdom implements the ETS are possible.
Liberalization of the UK natural gas market began in the mid-1980s. There is wholesale and retail competition in this highly liquid market. Natural gas suppliers have regulated open access to midstream and downstream infrastructure. Timely development of this infrastructure is necessary to avoid delays in upstream production or flaring. If there is a need for new capacity, suppliers can develop new infrastructure or transact with independent midstream companies to develop the needed infrastructure. Companies operating in the natural gas midstream and downstream need a license from the independent regulator Ofgem. Offshore producers need to develop infrastructure to deliver their associated gas to the national gas system. This infrastructure includes pipelines, terminals, processing plants, and storage facilities, some of which are located onshore. If relevant, the OGA issues flaring and venting consents for these facilities. Environmental regulators have jurisdiction over these facilities as well as the rest of the national gas system.
Colorado’s Greenhouse Gas Pollution Reduction Roadmap contains near-term and long-term targets, including for the oil and gas sector. Implementation of new rules to eliminate routine flaring and venting is mentioned as a near-term goal.
Based on the Colorado Oil and Gas Conservation Act, 1951, the Colorado Oil and Gas Conservation Commission (COGCC) has the authority to regulate and enforce the development and production of the state’s oil and gas resources in a manner that protects public health, safety, welfare, the environment, and wildlife resources. As per the Colorado Air Pollution Prevention and Control Act, 1984 , the Air Quality and Control Commission (AQCC) oversees the state’s air quality and emission efforts. It has the authority to adopt emission control regulations.
During drilling operations, Rule 903(b) of the Environmental Impact Prevention 900 Series, 2021, allows emergency flaring without prior notice when necessary to protect the safety of onsite personnel. However, a verbal notification must be provided to the COGCC within 12 hours of the event, and a written report must be submitted within 7 days.
Rule 903(c) requires operators to use reduced emission completion practices and enclose all flowback vessels to limit venting during completion operations. Flaring is allowed only with prior approval of the COGCC through a gas capture plan. Flaring is also allowed for a period not exceeding 24 hours during completion operations or for safety reasons during an upset condition. Rule 903(d) states that flaring or venting is prohibited during production operations unless one of the following exceptions applies: Flaring or venting lasting less than 24 hours is allowed during an upset condition. Operators must maintain records of the date, cause, duration, and estimated volume of gas vented or flared during each upset condition. Venting is allowed during active and required maintenance if it is in line with AQCC requirements, as long as the operator uses best practices to minimize venting during the maintenance or repair activity. Flaring lasting less than 24 hours can be allowed for safety considerations in the event of liquids unloading. For production evaluation and productivity testing purposes, flaring is allowed for up to 60 days, provided an approved gas capture plan is in place (see the next section). Flaring is allowed during wellhead pressure tests. If the gas release had not been authorized, Rule 912 requires the operator to notify the director of the COGCC within 24 hours and then produce additional data on the incident within 10 days of the event. In the case of intended flaring of hydrogen sulfide, Rule 612 of the Safety and Facility Operations Regulations 600 Series, 2021 , requires the operator to submit an air monitoring plan to the director of the COGCC before flaring.
Flaring approval during completion can be granted through an approved gas capture plan during the permitting process or a subsequent application explaining why flaring is necessary. The plan must detail how the operator will minimize adverse impacts and include information on the volume of gas that will be flared and the duration of flaring. All proposed new facilities must submit a gas capture plan as part of their permit application, in accordance with Rule 903.e. The gas capture plan must include a commitment to connect the production facility to a gathering line before production starts or a plan for how the operator will connect the facility to a gathering line or otherwise put natural gas to beneficial use. If the gas capture plan is not implemented, the director of the COGCC may require the well to be shut in until there is an acceptable gas capture plan. For wells completed before January 15, 2021, that are not connected to a gas gathering system or otherwise do not put natural gas to beneficial use, a formal application for permission to flare, including a gas capture plan, must be made. The director of the COGCC can approve the application once for up to 12 months, but in no case will such wells be allowed to flare or vent natural gas after January 15, 2022. According to Rule 904 of the Environmental Impact Prevention 900 Series, 2021 , starting in 2022, the director of the COGCC will carry out an annual environmental impact assessment of the cumulative impact of flaring and venting on key environmental metrics. Operators can be required to contribute as a condition of their development plans receiving approval.