Methane intensity is the metric that regulators, investors, and buyers increasingly use to compare the climate performance of oil and gas producers [1]. The number itself looks simple: total methane emitted from a defined operational boundary, divided by production volume [1]. Which emissions count in the numerator, and which volume goes in the denominator, shapes the result as much as the emissions themselves.

CATF’s February 2026 report shows that formula choice changes reported intensity and applies dissimilar stringency to oil and to gas (CATF, 2026) [2]. Because the EU import standard will be a single numeric threshold, that dissimilarity decides who clears it. For US operators exporting to Europe, the EU’s August 2030 enforcement deadline turns formula methodology into a market-access issue.

The Denominator Problem: Marketed Gas vs. Total Hydrocarbon Production

The most consequential methodological choice in any methane intensity formula is what goes in the denominator. OGCI defines upstream methane intensity as methane emissions from operated assets divided by total gas marketed (OGCI Reporting Framework, 2023) [1]. The boundary extends up to the first point of sale [1]. Marketed gas is the volume a company distributes to the market, sold or supplied free of charge, measured at that point of sale [1]. OGCI defines the point of sale as the place or device where ownership of the product transfers to the downstream player [1].

Gas that is flared, vented, burned as on-site fuel, or reinjected never reaches that point, so it never enters the denominator. Gas processed under a tolling agreement is excluded from the marketed volume, because the toller keeps ownership (OGCI Reporting Framework, 2023) [1]. The methane emitted while processing it still counts in the numerator [1].

OGCI set a combined membership target of “well below 0.20%” intensity by 2025, measured against this marketed-gas denominator (OGCI, 2023) [3]. Members reached the target in 2021, four years early (OGCI, 2026) [4]. For 2024, OGCI reported an aggregate upstream operated methane intensity of 0.12% (OGCI, 2026) [4]. That figure is 14% lower year on year and 62% below the 2017 baseline (OGCI, 2026) [4]. OGCI’s CEOs have since adopted a collective aim of 0.1% (OGCI, 2026) [4].

Clearing the target says less than the headline suggests. The 0.12% is self-reported by the 12 OGCI member companies and covers only assets they operate (OGCI, 2026) [4]. OGCI counts operated assets only, placing partner-operated assets outside the boundary for inclusion (OGCI Reporting Framework, 2023) [1]. The aggregate therefore describes a subset of world production, computed with whatever numerator method the members used.

The problem emerges when this formula is applied to oil-dominant producers. A facility that produces primarily crude oil with minimal associated gas has a very small marketed-gas denominator. Dividing even modest methane emissions by a tiny gas volume produces an extreme intensity figure. The facility’s physical emissions may be well-controlled.

CATF names two caveats specific to a gas-only denominator (CATF, 2026) [2]. The first is “Product Volume Bias”: for the same emissions, a producer that markets more gas records a lower intensity (CATF, 2026) [2]. The second is “Limited Applicability”: intensity “cannot be calculated for producers that do not produce the selected product” (CATF, 2026) [2].

The alternative approach uses total hydrocarbon production, converted to a common energy unit, as the denominator [2]. CATF expresses such denominators in units of energy or of oil equivalent, for example gigajoules, megajoules, or barrels of oil equivalent (CATF, 2026) [2]. A tonne of oil equivalent is written toe, and a million tonnes of oil equivalent is written Mtoe (OGCI Reporting Framework, 2023) [1]. CATF reviews the competing formulas and does not recommend any one of them (CATF, 2026) [2]. The energy-equivalent approach normalizes intensity across asset types, producing comparable figures whether the facility produces dry gas, wet gas, or crude oil with associated gas.

What the EU Methane Regulation Requires and What Remains Undefined

The EU Methane Regulation (EU/2024/1787) has been in force since August 4, 2024 [5]. Article 29(2) sets a maximum methane intensity value from August 5, 2030 [5]. The obligation covers supply contracts concluded or renewed after that date [5]. The Commission has not yet defined that maximum value or the calculation methodology.

Article 29(4) sets a deadline of August 5, 2027 for the delegated act carrying the methodology (EU/2024/1787) [5]. From January 1, 2027, importers must demonstrate equivalent monitoring, reporting and verification at producer level (EU/2024/1787) [5]. The duty covers contracts concluded or renewed on or after August 4, 2024 [5]. Annual methane intensity reporting begins August 5, 2028 [5].

The methodology the EU selects will determine which operators pass and which fail, independent of any physical change in their emissions. The compliance outcome changes with zero change in physical emissions.

Why Factor-Based Inventories Compound the Methodology Problem

Factor-based emission inventories understate the methane numerator, compounding the distortion introduced by denominator choice. Most operators build their reported methane numbers from bottom-up, factor-based inventories. Subpart W prescribes source-specific calculation methods rather than one formula (40 CFR Part 98, Subpart W) [6]. They range from direct metering and leak measurement through engineering estimation to default emission factors [6].

Where no measurement exists, an equipment count multiplied by a published factor produces the annual total (40 CFR Part 98, Subpart W) [6]. EPA proposed rescinding or suspending most of the program on September 16, 2025, and has taken no final action (90 FR 44591) [7]. Reports for the 2025 year are due October 30, 2026 (91 FR 9712) [7].

Three peer-reviewed studies size the gap. Omara et al. (2024) built a measurement-based national inventory from 1,540 facility measurements [8]. Their 2021 estimate is about 16 Tg, roughly 2x the EPA Greenhouse Gas Inventory [8]. Their estimate for production sites alone, about 9 Tg, is roughly 2.6x the inventory’s production-related figure [8].

Sherwin et al. (2024) integrated about one million aerial site measurements across six US regions [9]. Their six-region weighted average was 2.95% of covered gas production, roughly three times the national government inventory estimate [9].

MacKay et al. (2026) report a MethaneAIR loss rate of 1.6% of gross gas production, more than four times EPA’s 0.4% for the same regions [10]. Basin-level MethaneAIR totals run from 1.8x to 8.2x the corresponding EPA estimates [10].

The earliest study in this series found a smaller gap. Alvarez et al. (2018) put 2015 supply chain emissions at 13 Tg per year, about 60% above the EPA inventory [11]. The later studies cover more sites and more basins, and they report larger multiples. Satellite observations from TROPOMI independently corroborate the direction, showing Why Satellites Show About 2x More Methane Than Inventories at basin scale.

When an intensity metric divides an undercounted numerator by a contested denominator, the resulting number is unreliable in two independent dimensions. An operator reporting 0.15% intensity using factor-based emissions and a marketed-gas denominator could exceed 0.30% once measurement-based emissions and energy-equivalent normalization are applied.

The Mechanistic Air Emissions Simulator (MAES) was developed at Colorado State University and UT Austin [12]. MAES models emissions from fluid flow through equipment and from equipment states (Mollel et al., 2025) [13]. MAES generates expected emission ranges for specific facility types and configurations rather than single values (Mollel et al., 2025) [13]. TetraSoft uses MAES through a partnership with CSU [12].

Operator inventories often exclude emissions from failure events and unregulated sources (Santos et al., 2025) [14]. Applying MAES with aerial survey data in the Denver-Julesburg Basin added an estimated 16.4% of total emissions from abnormal events (Santos et al., 2025) [14].

A Measurement-Informed Inventory (MII) built on MAES is calibrated against field measurement data (Santos et al., 2025) [14]. Its numerator reflects measured facility behavior rather than a generic lookup table. For operators preparing to demonstrate methane intensity to European buyers, the numerator methodology matters as much as the denominator formula. Auditable, measurement-based emissions data reduces compliance risk regardless of which formula the EU adopts.

Frequently Asked Questions

What is methane intensity and how is it calculated?

Methane intensity is a ratio that expresses methane emissions as a proportion of production volume [1]. The numerator is total methane emitted (in volume or mass units) from a defined operational boundary [1]. The denominator varies by framework: some use marketed natural gas volume, others use total hydrocarbon production converted to energy-equivalent units [2].

Marketed gas is the volume delivered to a buyer at the first point of sale [1]. Energy-equivalent denominators use units such as gigajoules or million tonnes of oil equivalent, written Mtoe [1]. The choice of denominator materially affects the calculated intensity, particularly for operators with oil-heavy portfolios [2].

How should US exporters prepare for each EU methane regulation milestone?

Three phase-in deadlines each require different preparation [5]. For the January 2027 MRV equivalence deadline, exporters should verify that their monitoring, reporting, and verification documentation meets EU criteria now. For the August 2028 annual intensity reporting start, operators need a calculation methodology and baseline data established in advance.

The numerical intensity threshold takes effect August 5, 2030 for contracts concluded or renewed after that date. The Commission has not yet defined the limit or the formula. Operators can model their intensity under both marketed-gas and energy-equivalent denominators now to understand exposure under either outcome.

How are flared and vented volumes treated in each denominator formula?

The marketed-gas denominator excludes gas that is flared, vented, or consumed on-site, counting only gas reaching the point of sale. An energy-equivalent denominator based on total production may include those volumes depending on framework-specific boundary definitions. For operators with high flaring rates, the gap between the two formulas widens because the marketed-gas denominator shrinks while the energy-equivalent denominator does not. The EU has not yet specified which boundary definition will apply to the import intensity standard.

What should US operators exporting to Europe do now?

US operators with European off-take agreements should evaluate how their methane intensity would change under different denominator formulas (marketed gas vs. energy-equivalent). Operators should also assess whether their emissions numerator is defensible under measurement-based scrutiny. Factor-based inventories understate measured methane by at least 2x (Omara et al., 2024; Sherwin et al., 2024) [8]. Building a Measurement-Informed Inventory now provides lead time before the EU threshold becomes binding and supports OGMP 2.0 Level 4 and Level 5 Reporting Explained.

This post is for informational purposes only and does not constitute legal or compliance advice. Consult qualified legal counsel or a compliance professional for guidance specific to your operations and jurisdiction.

Interested in building a Measurement-Informed Inventory for your operations? Contact us to learn about our MAES-based estimation services.

References

  1. OGCI Reporting Framework, Final Version, October 2023. https://www.ogci.com/wp-content/uploads/2023/11/OGCI_Reporting_Framework_2023_-_FINAL_FINAL.pdf.
  2. Clean Air Task Force (CATF), “Methane intensity for oil and gas production: Key methodological considerations,” February 2026. https://www.catf.us/resource/methane-intensity-oil-gas-production/.
  3. OGCI, “Aiming for Zero Methane Emissions Initiative,” Guidance on Near-Zero Methane Emissions, 2023. https://www.ogci.com/wp-content/uploads/2023/08/OGCI-guidance-on-near-zero-methane-emissions.pdf.
  4. OGCI, “OGCI’s methane intensity target.” https://www.ogci.com/methane-emissions/methane-intensity-target/. Accessed September 9, 2026.
  5. Regulation (EU) 2024/1787 of the European Parliament and of the Council on the reduction of methane emissions in the energy sector, OJ L, 15 July 2024, in force 4 August 2024. https://eur-lex.europa.eu/eli/reg/2024/1787/oj.
  6. EPA Greenhouse Gas Reporting Program, Subpart W, Petroleum and Natural Gas Systems, 40 CFR Part 98, Subpart W (sections 98.230 to 98.238 and Tables W-1 to W-7).
  7. EPA, “Reconsideration of the Greenhouse Gas Reporting Program,” proposed rule, 90 FR 44591, September 16, 2025; “Extending the Reporting Deadline Under the Greenhouse Gas Reporting Rule for 2025,” 91 FR 9712, February 27, 2026.
  8. Omara, M., Himmelberger, A., MacKay, K., et al. “Constructing a measurement-based spatially explicit inventory of US oil and gas methane emissions (2021).” Earth System Science Data, Vol. 16, pp. 3973-3991, 2024. DOI: 10.5194/essd-16-3973-2024.
  9. Sherwin, E. D., Rutherford, J. S., Zhang, Z., et al. “US oil and gas system emissions from nearly one million aerial site measurements.” Nature, Vol. 627, pp. 328-334, March 13, 2024. DOI: 10.1038/s41586-024-07117-5.
  10. MacKay, K., Benmergui, J., Williams, J. P., et al. “Assessment of methane emissions from US onshore oil and gas production using MethaneAIR measurements.” Atmospheric Chemistry and Physics, Vol. 26, pp. 1179-1192, 2026. DOI: 10.5194/acp-26-1179-2026.
  11. Alvarez, R. A., Zavala-Araiza, D., Lyon, D. R., et al. “Assessment of Methane Emissions from the U.S. Oil and Gas Supply Chain.” Science, Vol. 361, Issue 6398, pp. 186–188, July 13, 2018. DOI: 10.1126/science.aar7204.
  12. Mollel, W., Zimmerle, D., Santos, A., & Hodshire, A. “Using Prototypical Oil and Gas Sites to Model Methane Emissions in Colorado’s Denver-Julesburg Basin Using a Mechanistic Emission Estimation Tool.” ACS ES&T Air, Vol. 2, Issue 5, pp. 723-735, 2025. DOI: 10.1021/acsestair.4c00168.
  13. TetraSoft corporate disclosure; MAES developed at Colorado State University and UT Austin and used by TetraSoft under partnership with Colorado State University.
  14. Santos, A., Mollel, W., Duggan, G. P., Hodshire, A., Vora, P., & Zimmerle, D. “Using Measurement-Informed Inventory to Assess Emissions in the Denver-Julesburg Basin.” ACS ES&T Air, Vol. 2, Issue 8, pp. 1598-1611, 2025. DOI: 10.1021/acsestair.5c00089.