How global oil and gas majors are committing to measured methane reporting

The methane reporting landscape for oil and gas has shifted meaningfully over the past several years, moving from a system built largely on generic emission-factor estimates toward one that expects actual, site-level measurement. OGMP 2.0 is the clearest expression of that shift, and its growing list of signatory companies - spanning international majors, national oil companies, and independent producers - signals that measurement-based reporting is becoming an industry-wide expectation rather than a niche practice.

What OGMP 2.0 actually requires#

OGMP 2.0, convened by the UN Environment Programme's Climate and Clean Air Coalition, defines five reporting levels of increasing rigour. The lower levels accept generic emission-factor-based estimates; the higher levels - up to Level 5 - require operators to reconcile those estimates against actual, direct site-level measurement data. Reaching and maintaining Level 5 reporting is a substantial operational undertaking: it requires the kind of continuous or frequent, asset-level monitoring infrastructure that generic estimate-based reporting never demanded.

Why the industry is moving this direction#

Several forces are converging to push methane reporting toward measurement rather than estimation. Regulatory pressure in multiple jurisdictions increasingly references or requires OGMP-aligned reporting. Investor and stakeholder scrutiny of climate disclosures has intensified, and generic emission-factor estimates have repeatedly been shown, in independent studies, to diverge - sometimes substantially - from what direct measurement reveals at specific sites and equipment. For companies managing reputational and regulatory risk around methane, being able to point to measured rather than estimated figures has become a meaningfully stronger position.

What this means operationally#

Meeting a higher OGMP 2.0 reporting level is not a paperwork exercise - it requires operators to actually deploy monitoring capability across their assets capable of producing genuine measurement data, not just periodic estimates. For midstream pipeline networks specifically, this means inspection and monitoring programs increasingly need to produce quantified findings - an actual measured or estimated leak rate tied to a specific location - rather than a qualitative "anomaly detected" flag. That requirement changes what counts as adequate inspection technology: a system that can only say "something looks unusual here" is less useful under measurement-based reporting than one that can attach a defensible quantitative estimate to a specific finding.

Where pipeline integrity technology fits into this shift#

Fugitive methane emissions from pipeline networks - valve and fitting leaks, pipeline damage, equipment failures - are a real and quantifiable contributor to an operator's overall methane footprint, which means pipeline inspection and integrity programs sit directly inside the scope of measurement-based reporting obligations, not adjacent to them. This is part of why inspection technology built to produce evidence-backed, quantifiable findings - rather than only flagging locations for further human review - has become more operationally relevant as OGMP 2.0 and similar frameworks have gained broader adoption across the industry.

A note on how we reference this#

We cite OGMP 2.0 and its signatory landscape here as public industry and regulatory context - not as a claim of partnership or engagement with any specific company named or implied by this framework. Sentrix is built with this reporting shift as part of the operating environment it's designed for, and quantification accuracy remains part of what we are actively validating rather than presenting as an already-proven capability.

Related reading#

This connects directly to methane regulation and reporting: a global comparison and to the economics of faster methane leak detection.