Country
Assessment
The US natural gas market is highly liquid and gas infrastructure is vast. Most of the transport pipeline and storage infrastructure operate as regulated open access facilities. Federal and state regulators share responsibility in licensing midstream and downstream infrastructure and regulating open access (for example, setting pipeline tariffs). Pipelines that cross state boundaries are subject to the oversight of the Federal Energy Regulatory Commission. Intrastate facilities are regulated by state regulators. Typically, independent midstream companies develop pipeline, processing, and storage facilities when they see an arbitrage opportunity to connect new production to consumers. Sufficient numbers of shippers or users must sign up for new capacity for midstream companies to justify investment. If midstream companies are not interested, it may be necessary for upstream companies, especially in offshore, to invest in pipelines. Delays in midstream infrastructure development have been a key reason for increased flaring in onshore upstream operations (see the case studies on Colorado, North Dakota, and Texas). The policy of the Federal Energy Regulatory Commission for analyzing GHG emissions associated with gas pipeline projects has been uncertain since about 2016. Arguments for including emissions from upstream (oil and gas production activities that supply the gas) and downstream (use of gas carried by the pipeline such as power generation) in the commission’s review of pipeline applications have led to court cases and disagreements among commissioners. In early 2021, the Federal Energy Regulatory Commission, for the first time, considered GHG emissions associated with pipeline construction and operation during its review of a pipeline. This change in the Federal Energy Regulatory Commission’s pipeline approval criteria may have unintended consequences by delaying pipeline development and causing increased flaring or venting of associated gas.
The updated waste prevention rule proposed in November 2022 sets new limits . The proposed rule allows only 48 hours of royalty-free flaring under emergency situations, which are defined more narrowly than before; and limits royalty-free flaring due to pipeline constraints, processing failures, or similar events to 1,050 cubic feet (mcf) per month, per lease, unit, or communitized area (see section 9 of this case study). The BLM can mandate operators to curtail or shut in production if reported flaring exceeds 4,000 mcf per month for three consecutive months and the BLM confirms that flaring is ongoing (Section 3179.8). The EPA’s proposed NSPS rule requires 95 to 100 percent reductions in methane and VOC emissions from various equipment such as pneumatic devices and storage vessels.
The Department of Interior’s BLM regulates flaring and venting from oil and gas leases on onshore federal and Indian lands. State regulators or tribal authorities may have rules, regulations, or orders governing flaring or venting of oil-well gas or emissions from flaring and venting. The BLM’s regional supervisors ratify such rules and any flare or vent authorizations issued by appropriate state regulators. The EPA has regulatory jurisdiction over air emissions from flaring and venting.
Title 43 CFR Section 3179.4 of BLM’s new rule proposed in November 2022 defines “unavoidably lost” gas when flaring is allowed royalty free—the operator must not have been negligent, must have taken prudent and reasonable steps to avoid waste, and must have complied fully with applicable laws, lease terms, regulations, provisions of a previously approved operating plan, and other written orders of the BLM. Section 3179.4(b) provides a list of 14 operations or sources from which lost gas may be considered as “unavoidably lost.” Many of these operations or sources have limitations or requirements detailed in other subsections to qualify. For example, 10,000 mcf during new hydraulic fracturing completions; 5,000 mcf during recompletions (wells connected to a pipeline); and 20,000 mcf total during initial production tests up to 30 days (with possible extensions to 60 days or 30,000 mcf). Venting is not allowed unless flaring or capturing are not technically feasible or in the case of emergencies. The proposed rule provides more detailed description of conditions under which venting may be allowed under Title 43 CFR Section 3179.6 (Safety). According to NTL-4A , which is in effect until the proposed rule is enacted, flaring or venting is allowed without royalty obligation or prior authorization from the BLM if volumes are considered “unavoidably lost,” defined as follows: Volumes are lost during temporary emergencies, such as the failure of a compressor or other piece of equipment, relief of abnormal system pressures, or other conditions that result in flaring or venting of gas. Such venting or flaring cannot exceed 24 hours per incident or a cumulative total of 144 hours for the lease during any calendar month. Volumes are lost during the unloading or cleaning up of a well during routine evaluation tests. Such flaring or venting cannot exceed 24 hours. Volumes are lost during initial production tests, not exceeding 30 days or 50 million cubic feet (mmcf) of gas, whichever occurs first. Gas vapors are released from storage tanks or other low-pressure production vessels. A BLM regional supervisor may determine that operators must recover such vapors. Oil and gas are lost as a result of line failures, equipment malfunctions, blowouts, fires, or similar events. If a BLM regional supervisor determines that the loss resulted from the negligence or failure of the operator to take all reasonable measures to prevent the loss, losses cannot be classified as “unavoidably lost.”
Flaring and venting are authorized under Subparts 3179.101 through 3179.104 of Title 43, which cover initial production testing, subsequent well tests, emergencies, and downhole well maintenance and liquids unloading. The proposed rule expands on these definitions. According to NTL-4A , prior authorization from a BLM regional supervisor is required if emergency flaring is expected to last longer than 24 hours. If a longer period of production testing is necessary, state regulators, if applicable, must authorize it, and the BLM regional supervisor must ratify this authorization. These requirements are essentially the same in the proposed rule. Gas from a gas well cannot be flared or vented except in narrow circumstances such as downhole well maintenance and liquids unloading that may cause gas flow to stop (limited to 24 hours according to the conditions outlined in Section 3179.204). Except when it falls under the “unavoidably lost” category (see the previous section), associated gas from oil wells cannot be flared or vented without written approval from a BLM regional supervisor.
The BLM’s 2016 Waste Prevention Rule required that a waste-minimization plan be submitted along with the application for an oil well drilling permit. The BLM rescinded this requirement in 2018. According to the BLM’s justification, at least some states have comparable gas capture requirements. In the rule proposed in November 2022, the BLM demonstrates that state programs are insufficient for the BLM, as the federal regulator, to assess potential waste during the permitting stage. Accordingly, the proposed rule requires operators to submit a plan to minimize waste of associated gas from an oil well along with the application for a permit to drill (APD). The plan must demonstrate how the operator plans to capture associated gas as soon as production starts, or justify any delays (adding Paragraphs [j] and [k] to Title 43 CFR Subpart 3162.3-1). The waste prevention plans are assessed using the concept of “unreasonable and undue waste of gas” defined in the rule as “frequent or ongoing loss of gas that could be avoided without causing an ultimately greater loss of equivalent total energy than would occur if the loss of gas were to continue unabated.” The BLM sought comments on this definition as it proposed to use it to approve, deny, or delay APDs.
According to NTL-4A , BLM regional supervisors consider the economics of a field-wide plan for oil and gas production for the leasehold. The BLM may approve an application for flaring or venting associated gas from oil wells if either of the documents below could justify the proposed action: A technical and economic report by the operator demonstrating that the expenditures necessary to market or beneficially use gas are not economically justified and conservation of the gas, if required, would lead to the premature abandonment of recoverable oil reserves and ultimately to a greater loss of equivalent energy than would be recovered with flaring or venting of the gas. An action plan from the operator that will eliminate flaring or venting within a year from the date of application. However, a 2016 GAO report found that the BLM’s field offices approved a large percentage of flaring and venting requests without the documentation required in the BLM’s guidance. About half of the approved operations were allowed to flare royalty-free. The GAO also observed that the BLM’s field offices had applied BLM guidance inconsistently and sometimes with significant differences. The rapid increase in drilling activity in tight oil and other unconventional plays since the early 2010s led to a significant increase in the number of applications for various permits to the BLM’s regional offices, overwhelming staff. The proposed rule does not allow case-by-case economic assessment of whether flared oil well gas can be considered royalty free.
According to NTL-4A , “the volume of oil or gas produced, whether sold, avoidably or unavoidably lost, vented or flared, or used for beneficial purposes must be reported.” The definition of beneficial purposes in NTL-4A is superseded by Title 43 Subpart 3178 , which primarily defines conditions for qualification as lease-use gas. Operators must also report to the regional supervisor “the volume and value of all oil and gas which is sold, vented or flared without the authorization” [of the supervisor], or those volumes deemed by the supervisor to be avoidably lost. All hydrocarbons produced from a well completion, including all gas flared, vented, and liquid hydrocarbons burned, must be reported on Form ONRR-4054, per Title 30 CFR § 1210.102. As with federal offshore, since September 15, 2010, leaseholders must specify flaring and venting volumes separately in the Oil and Gas Operations Report (OGOR) Part B. They must use different disposition codes for flared oil-well gas, flared gas-well gas, vented oil-well gas, and vented gas-well gas. According to NTL-4A, if the amounts of oil or gas involved have been measured, the measured volumes must be reported. Estimation criteria are provided. Metering is not required, but the BLM’s regional supervisors may require the installation of additional measuring equipment if the goals of NTL-4A are not met with existing equipment or estimation methods. Separately, operators must follow the guidance of Title 43 Subpart 3175 on gas measurement. This subpart has clauses on gas metering technology, hardware, and software requirements for metering, performance standards, and record-keeping requirements to ensure accurate royalty calculations.
According to Title 43 CFR § 3163.1, in the event of failure or refusal to comply with BLM regulations, the terms of any lease or permit, any notice, or order requirements, the regulator notifies the party concerned in writing of the violation. A fine of US$1,000 per violation a day for major violations and a fine of US$250 per violation a day for minor violations may be imposed. According to Title 43 CFR § 3163.2, for failure or refusal to comply within 20 days (or another time period set by an authorized officer of the BLM) of the violation notice, the operator is liable for a civil penalty, which can be as high as US$5,000 per violation a day for up to 60 days. According to the BLM’s proposed rule, all flares or combustion devices must be equipped with an automatic ignition system. Upon discovery of a flare that is not lit, the BLM may subject the operator to an immediate assessment of US$1,000 per violation (Section 3179.6). The IRA of 2022 introduced a methane penalty. Starting in 2025, facilities emitting more than 25,000 tonnes of methane per year are subject to the penalty (see section 18 of the preceding case study, on US federal offshore production).
According to Title 43 CFR § 3163.1, “when necessary for compliance, or where operations have been commenced without approval, or where continued operations could result in immediate, substantial, and adverse impacts on public health and safety, the environment, production accountability, or royalty income,” the regulator may shut down operations after due written notice. Immediate shut in is possible if a BLM regional supervisor deems the offense severe enough. Continued noncompliance may lead to lease cancellation. According to Title 43 CFR § 3163.2, in addition to civil penalties, there can be criminal penalties of up to two years of imprisonment.