Flaring and venting have been regulated in Texas for decades, but flare volumes soared, from about 35 billion cubic feet (bcf) in 2011 to 263 bcf in 2020, according to data from the Energy Information Administration. The increase reflected a ramp-up in drilling activity in the Permian, Eagle Ford, and other plays and the inability of the midstream gas infrastructure to grow in parallel with associated gas production. The Permian Methane Analysis Project found that about 11 percent of Permian flares surveyed were either unlit or malfunctioning.

In response, the state oil and gas regulator, the Railroad Commission (RRC), revised its reporting requirements. The RRC’s number of authorizations for flaring and venting increased from 107 in 2008 to 6,972 in 2019 . The rise in flare permitting has been steady, except in 2016 and 2017, when the oil price slumped. The industry is trying to improve its performance, but the lack of gas pipeline and processing capacity remains the leading cause of continued flaring. According to data from the Energy Information Administration, Texas has flared 70–90 cf per barrel of oil produced since the 1990s, but its flaring intensity doubled to 140–150 cf per barrel in 2018 and 2019.

Although they were eventually abandoned, the Texas Legislature considered two bills on emissions and flaring by the oil and gas industry in early 2021.

There is a 10-day limit on flaring during drilling and well testing. Once testing is over, the RRC can authorize further flaring up to 180 days. Operators may release low-pressure-separator hydrocarbons, up to 15 thousand cubic feet (mcf) a day from a gas well or 50 mcf a day, from an oil lease or commingling point for commingled operations (see sections 9 and 10 of this case study).

The Texas Natural Resources Code’s Chapter 85 declares the waste of oil and gas resources “illegal and prohibited.” With respect to flaring, the RRC implements this clause using Texas Administrative Code, Title 16, Part 1, Section 3.32, known as Statewide Rule 32. The rule outlines the conditions under which flaring may be allowed. In response to increased flaring volumes and public scrutiny, the RRC published a new Application for Exception to Statewide Rule 32 in late 2020 but did not change the rule (see section 10 of this case study).

The Texas Air Quality State Implementation Plan (SIP) was adopted in 2004 and approved by the Environmental Protection Agency (EPA) in 2006. Texas’ SIP Vent Gas Control program (Sections 720–729 of Chapter 115, entitled “Control of Air Pollution from Volatile Organic Compounds”) is most relevant for oil and gas operations. There is also a greenhouse gas (GHG) permitting program at the Texas Commission on Environmental Quality (TCEQ), but it focuses primarily on power plants based on the EPA’s GHG program under the Clean Air Act, 1990.

Flaring and venting in Texas are primarily state matters; federal onshore regulations are largely irrelevant in Texas. The share of producible completions in Texas out of total producible completions across all federal lands approved by the Bureau of Land Management (BLM) was about 0.5 percent through the 2010s. With respect to air emissions, the EPA plays a role by approving SIPs.

Land ownership determines mineral rights. About 12 percent of Texas is public land managed by the General Land Office. Revenue from mineral resources developed on these lands is used for public education. Federal lands account for only about 1 percent of all land in Texas. In the rest of the state, private landowners own the rights to mineral resources. In many cases, mineral rights may be severed from surface rights but are still held privately. Companies obtain a concession from the mineral rights owner to explore for oil and gas. In the case of a commercial discovery, the concessionaire owns oil and gas under the leased area. Under most private leases, royalties are not paid on lost gas, which includes flared and vented volumes.

The RRC regulates the exploration, production, and transport of the oil and gas industry. The TCEQ regulates air emissions.

The RRC has jurisdiction over the permitting of flaring operations with respect to preventing the waste of natural resources. The TCEQ is charged with reviewing and approving air pollution permits for industrial and commercial sources, including flaring and venting.

The RRC’s inspectors (usually housed in district offices closer to operations) can visit sites “to witness operations, conduct inspections, provide information about permitting requirements, and ensure compliance with permits issued by the Commission” . State policy and regulation have focused on economic development and job creation. The RRC’s commissioners are not appointed but are elected, creating the risk for inherent tension between the regulator’s duties to protect the environment and to steward the efficient development of mineral resources. Separately, per SIP, the TCEQ is expected to conduct inspections at least quarterly to ensure the proper operation of continuous monitoring systems and pressure valves.

Statewide Rule 32  allows operators to flare oil-well gas while drilling a new well and testing the well for up to 10 days. Venting is allowed for releases lasting less than 24 hours, unless flaring is necessary for safety reasons; operators are encouraged to verify with RRC District Offices whether they can vent or must flare. Gas that must be unloaded from a well may be vented for up to 24 hours in one continuous event or up to 72 cumulative hours in one month.

Statewide Rule 32  allows operators to flare oil-well gas beyond the initial 10 days with an exception to Rule 32 issued by the RRC. Typically, exceptions are not granted for flaring from gas wells. Flaring exceptions are granted for 45 days at a time for up to 180 days. More documentation is required every time an operator applies for an extension. Exceptions beyond 180 days must be approved by an RRC final order after a hearing. An exception may be approved administratively and indefinitely if flaring is less than 50 mcf a day at an oil well and 15 mcf a day at a gas well.

According to the RRC, most exceptions are for flaring casinghead gas from oil wells. Flaring could be necessary for extended periods if the well is drilled in new exploration areas without sufficient gas pipeline or processing capacity. Other acceptable reasons include processing plant shutdowns and repairs or maintenance at production or pipeline facilities such as compressors .

Separately, operators should apply for standard air permits from the TCEQ if activities (such as flaring) are considered “routine events.” The TCEQ provides guidelines for standard air permits. These permits do not authorize emissions from upsets, emergencies, or malfunctions. They cover volatile organic compounds, particulate matter, and oxides of nitrogen but do not cover methane and carbon dioxide.

No evidence regarding development plans could be found in the sources consulted.

In late 2020, the RRC updated Statewide Rule 32  Exception Data Sheet (Form R-32), used by operators to apply for flaring exceptions. After collecting comments from stakeholders on a draft, it published a new version, entitled “Application for Exception to Statewide Rule 32.” The new form requires operators to include technical and economic justifications with the goal of reducing the duration of flaring exceptions. This specific information enables the RRC to assess compliance by identifying and tracking the location of flare and vent points. The documentation required includes a cost-benefit analysis, a map showing the nearest pipeline capable of accepting gas, and an estimate of gas reserves. In most cases, the changes are expected to reduce the time an operator may obtain an administrative exception to flare by 50–80 percent.

Operators must report volumes of gas flared to the RRC using the monthly production report (Form PR). This report must include metered gas volumes from both gas wells and casinghead gas from oil wells at the lease level . The RRC updated instructions for completing Form PR and instructed operators to report flaring and venting separately and remark on the status of the RRC exception for each flaring or venting event. The RRC also developed an online system for the flare and vent program. This system includes information on flaring and venting applications.

Texas SIP Vent Gas Control regulations  require the operator of each affected flare or vent gas stream to adhere to reporting and record-keeping requirements, which include the development and implementation of a quality assurance plan for the monitoring requirements, including installation, calibration, operation, and maintenance of continuous emissions monitoring systems. Separately, operators must submit written notification to the regional office of the EPA at least 45 days before conducting any flare and vent gas stream testing, as required by Texas SIP.

Operators must file RRC Form PR  monthly. Historically, flared and vented gas volumes were reported together in Form PR, but new RRC instructions require that operators report them separately starting in September 2021.

Texas SIP Vent Gas Control regulations  require operators of affected flares to install an on-line analyzer system capable of determining highly reactive volatile organic compounds at least once every 15 minutes. The system must also measure other potential emissions—such as hydrogen, nitrogen, carbon dioxide, methane, and other volatile organic compounds—sufficient to determine the molecular weight and net heating value of the gas combusted in the flare to within 5 percent.

Part 1, Section 3.27 of Texas Administrative Code, Title 16 , details measurement requirements and standards for RRC Form PR  reporting. According to Texas SIP Vent Gas Control regulations, the flow rate of the gas routed to the flare, in standard cubic feet per minute, must be determined by either complying with the monitoring requirements or using process knowledge and engineering calculations.

No evidence regarding record-keeping requirements could be found in the sources consulted.

Data from RRC Form PR  are available on the RRC website. TCEQ air emissions data are available in various formats. Several data sets include volatile organic compounds and point sources. The Energy Information Administration compiles data from states and reports on its website, but the data are incomplete (see section 17 of the case study on US federal onshore production).

Most violations, including the violation of flaring exceptions, are resolved through the RRC’s district offices by means other than administrative penalties. Nevertheless, the RRC has statutory authority to assess administrative penalties for violations related to safety, environmental, and other permits according to Texas Natural Resources Code Subsections 81.0531 through 81.0533. The RRC may assess up to US$10,000 a day per violation and US$1,000 a day for non-safety- or pollution-related violations. Part 1, Section 3.107 of Texas Administrative Code, Title 16 , provides guidelines on penalties for various types of oil and gas violations. The RRC considers the seriousness of the violation, the operator’s history of compliance, and other relevant factors to determine the amount of the penalty.

According to Subsections 91.701–91.707 of Texas Natural Resources Code, Title 3, the RRC may cancel a certificate of compliance after issuing a notice of violation to the operator. Once the certificate is canceled, operations must stop. The RRC can also modify, suspend, or terminate a permit if there is a violation.

The TCEQ provides guidance on how flares must be designed and operated, based on the specifications of Title 40 Code of Federal Regulations (CFR) § 60.18. Among other requirements, it requires flares to be always operated with a flame present or have a constant pilot flame, which should be continuously monitored by a thermocouple, infrared monitor, or ultraviolet monitor. There should be no visible emissions, except during periods not exceeding a total of five minutes during any two consecutive hours.

Part 1, Section 3.103 of Texas Administrative Code, Title 16 , provides for an incentive to market flared or vented gas via an exemption from the state severance tax of 7.5 percent on the marketed gas volume for the life of the well. To qualify, such marketed gas should have previously been vented or flared for 12 months or more. However, this incentive is at least partially negated by Subtitle I, Section 201.053 of Texas Administrative Code, Title 2, which exempts oil-well gas that is lawfully vented or flared from the severance tax.

The TCEQ operates several cap-and-trade programs, but they focus on urban air quality, mostly in Houston’s eastern Gulf Coast region. They do not capture volatile organic compounds from oil and gas operations in most of the state. There is no similar program for GHGs.

No evidence regarding negotiated agreements between the public and the private sector could be found in the sources consulted.

The primary reason for flaring in the Permian Basin has been the lack of natural gas pipeline capacity to transport gas to markets. Several natural gas pipelines have been built or are under construction to transport gas to markets, including LNG facilities. In the meantime, because the impact of gas sales on overall well economics has been limited, the RRC appears unlikely to restrict oil production to reduce flaring. For example, in May 2020, the RRC rejected a proposal to cut oil production by 20 percent in a 2 to 1 vote. The split decision was based on the expectation that the issue would resolve itself once the necessary infrastructure was built. However, the RRC’s new requirement of more detailed economic justifications before approving flaring exceptions may change the current situation. As highlighted in the Texas Natural Resources Code, preventing the waste of the state’s natural resources is attracting attention.

Some Permian Basin producers, mainly small ones, argue that delaying well completions or reducing oil production rates while waiting for sufficient gas takeaway capacity will lead to an immediate loss in income that far exceeds any future revenue increase from gas sales. Major producers in the Permian Basin treat gas takeaway capacity as a manageable constraint that involves ensuring that adequate takeaway infrastructure is in place before bringing a well online and being willing to shut in a well until takeaway capacity is secure. Ongoing consolidation among operators is reinforcing this trend.