Natural Gas Flaring by State, 2015 to 2024

Oil wells flare natural gas because the gas comes up with the oil, and when no pipeline or processing plant can take it, burning it at the site is the legal fallback the states allow, within limits. In 2024 the United States vented and flared 335,163 million cubic feet (MMcf), or 0.73% of gross withdrawals, according to EIA data. Texas accounted for 163,512 MMcf of that, North Dakota 67,705 and New Mexico 17,026.

Volume and intensity rank the states differently. Texas burns the most gas because it produces the most, yet its share of gross withdrawals was 1.27% in 2024. North Dakota flared 5.40% of its gross withdrawals, down from 19.35% in 2019, and New Mexico flared 0.47% while its production nearly tripled over the decade. Wyoming moved the other way: it vented and flared 3,473 MMcf in 2015 and 59,941 MMcf in 2024, more than New Mexico, a state that withdraws more than two and a half times as much gas, and 4.46% of its own gross withdrawals. For where the oil itself comes from, see U.S. oil production by state.

Why an oil well ends up burning its gas

A shale oil well does not produce only oil. The EIA uses the term associated natural gas for gas extracted during oil production, and in basins such as the Permian and the Bakken that gas arrives in large volumes. An operator drilling for oil has three places to send it: a gathering line to a processing plant, use on the lease (for engines, heaters or reinjection), or a flare. The EIA’s 2020 analysis of record flaring put the cause plainly: crude oil production outpaced the construction of the infrastructure needed to move associated gas, and the gas was increasingly vented and flared.

The EIA lists the occasions in a 2024 explainer: emergencies, safety tests, maintenance and repairs, and infrastructure constraints. When pipeline takeaway capacity is limited, it says, operators sometimes vent or flare gas that cannot be economically stored, depending on the rules of the state they operate in. The Railroad Commission of Texas gives its own list from the permitting side. In new exploration areas, pipeline connections are usually not built until a well is completed and its productive capability is known, so the gas from the first months has nowhere to go. In established areas, gas plant shutdowns, repairs to a compressor, a gas line or the well, and pipelines that have reached capacity also lead to flaring.

One detail from North Dakota changes the picture. The Industrial Commission’s gas capture guidance says its production records indicate that the majority of gas flared in the state comes from wells already connected to a gas gathering system. A connection is necessary, but it is not sufficient: if the gathering line, compressor station or processing plant downstream is full or down for maintenance, a connected well still flares. That is why both the Texas and North Dakota rules talk about capacity and downtime, not only about connecting new wells.

Flaring versus venting

Venting releases gas into the air unburned. Flaring burns it, which the EIA says converts a portion of the gas to carbon dioxide while some unburned methane still escapes. The EIA notes that regulators prefer flaring where possible because methane is the more potent greenhouse gas, and it described venting in 2020 as banned in North Dakota and restricted in Texas. New Mexico’s rule writes the preference into law: operators shall flare rather than vent except where flaring is technically infeasible or would pose a safety risk. The EIA’s state data do not separate the two. Every number in the tables below is the combined vented and flared volume, and the mix inside it differs from state to state.

Vented and flared gas by state, 2015 to 2024

Table 1 gives the raw volumes for every state that reports a nonzero figure to the EIA, plus the federal offshore Gulf. Table 2 divides each volume by the same state’s gross withdrawals, which is the fairest comparison between a state that produces 13 trillion cubic feet a year and one that produces less than 50 billion. Gross withdrawals, in the EIA’s definition, are the full well-stream volume, including natural gas plant liquids and nonhydrocarbon gases but excluding lease condensate.

Three things stand out. First, the national share peaked at 1.32% in 2019 on 539,480 MMcf and from 2021 to 2024 stayed between 0.6% and 0.75%, even though U.S. gross withdrawals grew 39% from 2015 to 2024. Vented and flared volume grew 16% over the same span, so the decade ends with more gas burned in absolute terms and a smaller share of output. Second, the volume is concentrated: in 2024 Texas, North Dakota and Wyoming together accounted for 86.9% of the U.S. total. Third, intensity is not where the volume is. Montana flared 11.55% of a small gross withdrawal base, and the federal offshore Gulf ran above Texas in share in six of the ten years.

How the shares are built, and the checks that keep them honest

The arithmetic is a single division, but the inputs carry conditions worth knowing before quoting any state’s number. Both series come from the EIA’s Natural Gas Annual tables. The EIA’s table notes say that since 2011, annual state repressuring, vented and flared, and nonhydrocarbon volumes have been obtained directly from state agencies, state-sponsored public record databases or commercial data vendors, with the federal offshore Gulf supplied by the Bureau of Safety and Environmental Enforcement. So each state number is only as complete as that state’s own reporting.

The first check is the sum. For 2024, the eleven rows in Table 1 add up to 335,164 MMcf against a published U.S. total of 335,163, a gap of 1 that is rounding. In 2018 the rows sum to 470,595 against 470,601, the difference being small volumes reported elsewhere (Idaho shows 7 MMcf that year). The year that does not close without help is 2015: the rows sum to 275,588, and the remaining 13,957 MMcf in the U.S. total is attributed to South Dakota, against South Dakota gross withdrawals of 14,510 MMcf that year. That single entry is almost the whole of a small state’s output, and it disappears from 2016 onward, so it is best treated as a reporting artifact rather than a fact about South Dakota wells.

The second check is coverage. Several large producers, Pennsylvania, Oklahoma and Ohio among them, show zero in every year, and Arkansas, Kansas and West Virginia show NA for 2016 to 2018. The EIA explains this directly: the Natural Gas Annual relies on vented and flared data reported by the states, and some states do not collect or publish any. Its 2024 note names the reporting states as Alaska, California, Colorado, Louisiana, New Mexico, North Dakota, Texas, Utah and Wyoming. Montana also carries nonzero values in the published series and is included here. A zero for Oklahoma means no report, not no flaring, and the U.S. total is therefore a total of what is reported.

The third check is discontinuity. Wyoming’s share jumps from 0.56% in 2019 to 4.10% in 2020 and stays above 4% afterward. California goes from zero to about 1% in the same year, and Utah returns from NA in 2019. The EIA table notes do not give a reason for these steps, and a change that abrupt in one year is more consistent with a change in what is reported than with a change in operations. The figures are shown as published; trends across 2019 and 2020 for those three states should not be read as a real increase without the state’s own records.

Texas: the largest volume at a modest share

Texas vented and flared 163,512 MMcf in 2024, about 447 MMcf a day, or 48.8% of the national total. Its share of gross withdrawals was 1.27%. The series tells a story of one squeeze and one recovery. Volumes more than doubled from 96,946 MMcf in 2017 to 238,054 in 2018 and 251,186 in 2019, pushing the share to 2.61% and 2.41%. Those are the years the EIA describes as Permian gas production growing faster than pipeline takeaway. The share then fell to 0.95% in 2021 and 0.87% in 2022 as new pipelines came into service, before rising to 1.28% in 2023 and 1.27% in 2024 on higher volumes. The Permian Basin production outlook covers the pipeline queue that decides whether the next squeeze arrives.

Texas regulates flaring as a waste question. The Railroad Commission of Texas says it has jurisdiction over flaring with respect to preventing waste of natural resources, while the Texas Commission on Environmental Quality handles air quality. Its Statewide Rule 32 (16 Texas Administrative Code §3.32) requires that all gas from wells, gathering systems and plants be used for purposes authorized by law, then allows flaring during drilling and for up to 10 days after completion for well potential testing. Past that, the operator needs an exception, issued administratively for 45 days at a time to a maximum of 180 days, with anything longer requiring a Commission Final Order. The Commission says most exceptions are for casinghead gas from oil wells, and that long-term exceptions are not typically issued for gas wells because gas is their main product.

The exceptions count and the volume moved together in 2019, when the Commission issued 6,972 exceptions, its highest figure in the series, and Texas flared its record volume. They part ways elsewhere. In fiscal 2015 the Commission issued 5,689 exceptions, yet the 2015 share was 1.29%, close to its 2023 level. An exception is a permission covering a well, lease or flare point, not a measure of gas, so a count can rise while volume falls. The volume figure is the one to track: the Commission says operators must report actual metered flared volumes of gas well gas and casinghead gas, by lease, on the monthly production report, Form PR.

North Dakota: from 19% of its gross gas to about 5%

North Dakota has had the highest flaring share of any large producing state for most of the decade. In 2019 it vented and flared 205,278 MMcf, 19.35% of its gross withdrawals; in 2024 the figure was 67,705 MMcf, or 5.40%. Over the same years its gross withdrawals grew from 1,061,091 to 1,253,369 MMcf. The volume fell by about two thirds while production rose, which is what a capture policy is supposed to produce.

The EIA traces the cause to the Bakken: crude development outpaced the region’s ability to process and transport associated gas, and in 2013, the year before capture targets took effect, more than 30% of the gas produced in the state was flared. The fix was steel. The EIA reported, citing the Industrial Commission, that the state’s gas processing capacity rose from 1 billion cubic feet a day in 2013 to 3.4 in 2020, and that pipeline capacity to move natural gas liquids out of the region grew from 60,000 barrels a day in 2013 to more than 580,000 by September 2021. The liquids line matters because, as the EIA notes, a processing plant cannot run without an outlet for the liquids it strips out, and gas cannot enter interstate pipelines until they are removed.

Two layers of rules apply. The statute, North Dakota Century Code 38-08-06.4, allows gas produced with crude oil to be flared for one year from first production. After that the well must be capped, connected to a gathering line, or fitted with equipment that uses or captures gas: an electrical generator consuming at least 75% of the gas, a system taking at least 75% of the gas and liquids for beneficial use, or another approved process that cuts flare volume or intensity by more than 60%. A well flaring in violation owes royalties to royalty owners on the value of the flared gas and gross production tax on it. The Industrial Commission can grant an exemption when a connection is economically infeasible or no market exists.

The second layer is Industrial Commission Order 24665 and its Policy/Guidance, which set capture goals that stepped up from 74% in late 2014 to 91% beginning November 1, 2020. The Commission says it evaluates compliance statewide, by county, by field and then by well for each operator, and that an operator missing the goal at its maximum efficient rate has its wells restricted to 200 barrels of oil a day if at least 60% of associated gas is captured, or 100 barrels a day otherwise. The guidance also concedes a ceiling: because of operational, maintenance and safety limits, the maximum actual capture percentage will average 96% of nameplate capacity. The EIA reported that North Dakota producers captured 92.5% of produced gas in the first nine months of 2021, meeting the 91% goal.

Why 5.40% flared does not mean 94.60% captured

The state’s capture percentage and the EIA share use different inputs. The guidance formula is one minus (gas flared minus approved variances) divided by associated gas produced, times 100. Variances cover the first 14 days of flowback, 31 days of initial production testing, documented force majeure, midstream maintenance, new wells joining a system, right-of-way delays and several other cases. The EIA share divides all vented and flared gas by all gross withdrawals. Take an operator whose wells produce 100,000 Mcf of associated gas in a month and flare 9,000 Mcf, of which 2,000 Mcf is documented flowback covered by a variance. The plain flared share is 9%. The Commission’s capture figure is (1 - (9,000 - 2,000) / 100,000) x 100 = 93%, which meets the 91% goal. Both numbers are correct for their purpose; they answer different questions.

New Mexico: production nearly tripled, the share fell to under half a percent

New Mexico’s gross withdrawals rose from 1,296,793 MMcf in 2015 to 3,616,820 in 2024, a factor of 2.8. Its vented and flared volume fell from 24,850 to 17,026 MMcf over the same span, so the share dropped from 1.92% to 0.47%, the lowest in the series. Like Texas, New Mexico had its worst years in 2018 and 2019 (2.43% and 2.05%); unlike Texas, its share stayed below 0.8% from 2021 onward and fell again in 2024.

The state’s rule, 19.15.27 NMAC, took effect May 25, 2021. It declares venting or flaring that constitutes waste prohibited and gives operators a general duty to maximize recovery of gas. During production, venting and flaring are allowed only in listed cases: emergencies and malfunctions, liquids unloading under conditions, the first 12 months from an approved exploratory well, routine operations such as tank gauging or compressor operation, short production tests, and gas that does not yet meet pipeline specifications. During completions, gas that misses pipeline specifications may be flared for up to 60 days or until it meets them, whichever is sooner, with twice-weekly sampling.

The rule’s headline is a statewide capture requirement. Starting April 1, 2022, each operator must reduce its annual vented and flared volume so that it captures no less than 98% of the gas produced from its wells in each of two reporting areas, north and south of the Township 10 North line, by December 31, 2026. The deadline is two months after this page was written. Operators started from a baseline rate the Division calculated from their fourth-quarter 2021 and first-quarter 2022 reports, and must raise capture each year by the baseline loss rate minus two percentage points, divided by five. An operator starting at 85% capture has a loss rate of 15%, so its required annual gain is (15 - 2) / 5 = 2.6 percentage points, which falls inside the rule’s own example band of more than 1.6 to 3.6 points for baselines of 80% to 89%. Below a 60% baseline, the operator must file a plan with the Division. This page shows where the rule required operators to be; it does not report operator compliance, which the Division publishes separately.

The three rulebooks side by side

The table condenses each state’s official text to the questions a reader usually has: when flaring is allowed without asking, how long a waiver lasts, what target applies and what happens to a well that misses it. Each row is dated to the check of the official page.

The approaches differ in kind. Texas runs a permit clock: short default windows and exceptions that must be renewed with evidence of progress, which the Commission says most often means a pipeline scheduled for completion by a stated date. North Dakota sets an outcome, a capture percentage, and enforces it with production limits and with money, by charging royalties and tax on flared gas after the first year. New Mexico combines a near-total ban on routine flaring with an operator-level capture target, the strictest numeric goal of the three.

What the gas is worth, as a sense of scale

Volumes in million cubic feet are hard to picture. The U.S. total of 335,163 MMcf in 2024 is about 916 MMcf a day, or 0.92 billion cubic feet a day over the 366 days of a leap year. At the EIA’s 2024 heat content for gas delivered to consumers, 1,037 Btu per cubic foot, the year’s 335,163 MMcf is about 348 million MMBtu a year. At the 2024 Henry Hub spot average of $2.19 per MMBtu, it would be worth about $760 million a year, or about $2.1 million a day.

That figure gives scale; it is not a loss estimate. Raw associated gas is richer than pipeline gas, so its heat content per cubic foot is higher than the delivered figure; Henry Hub is in Louisiana, while flared gas sits in basins where, as the EIA showed for Waha, local prices can run well below it; and gas that is flared because there is no outlet could not have been sold at any price that month. The EIA lists the parties who lose when gas is flared: operators lose revenue, states lose taxes, and mineral owners and lease holders, including federal and tribal governments, lose royalties. The North Dakota statute is written with that last loss in mind.

Wyoming, Montana and the offshore Gulf

Wyoming was the third-largest source in 2024 at 59,941 MMcf, 4.46% of gross withdrawals and 17.9% of the U.S. total, while its gross withdrawals fell from 1,995,920 MMcf in 2015 to 1,343,290. Given the 2020 step discussed above, the comparison that holds is 2020 to 2024, over which the share moved between 4.10% and 4.78%. Montana’s share swings with a small denominator: 11.82% in 2015, 6.23% in 2023 and 11.55% in 2024, on gross withdrawals under 60,000 MMcf. A few wells or one plant outage can move it by several points.

The federal offshore Gulf ran between 0.83% and 1.51% across the decade, on falling gross withdrawals, and its share was above the Texas share in six of the ten years. Alaska is the opposite case: 3,549,165 MMcf of gross withdrawals in 2024, nearly as much as New Mexico, and a flared share of 0.18%. The EIA’s Alaska repressuring series (N9020AK2) shows 3,170,978 MMcf returned to reservoirs that year, 89% of gross withdrawals, a use the EIA counts as repressuring rather than venting or flaring. Louisiana and Colorado, both large gas states, flared 0.05% and 0.01% in 2024; for a gas well the gas is the product, and the Railroad Commission of Texas says it does not typically issue long-term flaring exceptions for gas wells.

Five things to check before quoting a flaring figure

1. Is the number vented and flared combined, or flaring alone? EIA state data combine them.
2. Is it a volume or a share, and if a share, of what: gross withdrawals, marketed production or associated gas?
3. Does the state report at all? A zero from a non-reporting state is missing data.
4. Is the year final? The EIA’s preliminary 2023 estimate of 0.5% became 0.71% for the U.S. and 1.28% for Texas.
5. Is a capture percentage a regulator’s figure with variances removed? Then it will not match the EIA share.

Flaring is the visible end of a takeaway problem, and the price signal for that problem is regional. If you want to see how a local hub such as Waha is set against the national price, and why it can drop below zero when pipes fill, the Henry Hub, TTF and JKM comparison walks through how gas benchmarks are formed.

Data and sources: U.S. Energy Information Administration, Natural Gas Vented and Flared and Natural Gas Gross Withdrawals by state, annual, with the per-state history pages (for example N9040TX2 and N9010TX2), release dated October 30, 2026, checked October 30, 2026. EIA, Gross Withdrawals and Production definitions and sources, checked October 30, 2026. EIA, Today in Energy: Natural gas venting and flaring in North Dakota and Texas increased in 2019 (December 8, 2020); North Dakota’s natural gas producers meet the state’s natural gas capture target (December 8, 2021); The Waha Hub natural gas price continues to fall below the Henry Hub price (September 20, 2022); Our estimated rate of U.S. natural gas vented or flared declined in 2023 (June 20, 2024); all checked October 30, 2026. EIA, Henry Hub Natural Gas Spot Price, annual and Heat Content of Natural Gas Delivered to Consumers, checked October 30, 2026. EIA, Alaska Natural Gas Repressuring (N9020AK2), checked October 30, 2026. Railroad Commission of Texas, Flaring Regulation FAQ, checked October 30, 2026. North Dakota Legislative Branch, Century Code chapter 38-08 (section 38-08-06.4), checked October 30, 2026. North Dakota Department of Mineral Resources, Order 24665 Policy/Guidance, Version 09-22-2020, checked October 30, 2026. New Mexico State Records Center and Archives, 19.15.27 NMAC, Venting and Flaring of Natural Gas, checked October 30, 2026. Shares, sums, daily rates, the energy and value conversion and both worked formulas are this page’s arithmetic.