Most sectors have one hard measurement problem. Oil and gas has three, and they attract different kinds of attention.
The first is direct emissions at scale: combustion, flaring, venting and fugitive releases across facilities that are frequently remote and sometimes not continuously metered. The second is methane, which has a global warming potential many times that of CO₂ over a twenty-year horizon and is therefore disproportionately significant relative to the volumes involved. The third is category 11 — the emissions from the use of what you sell — which for a producer of hydrocarbons is typically an order of magnitude larger than everything happening at your own facilities.
On top of that sits the highest level of external scrutiny of any Nigerian sector. Satellite flare monitoring means your reported flare volumes are checkable by anyone with an internet connection, and they are checked.
You already report production, flare and vent volumes to Nigerian regulators, and you already report under the flare gas commercialisation and gas flaring penalty regimes. Those figures are in the public domain in one form or another.
Your sustainability disclosure must be reconcilable with them. Where the numbers differ — because of boundary, timing, joint venture interest or measurement basis — the difference has to be explicable. Two sets of flare figures with no bridge between them is a finding, and it is the kind of finding that generalises: a reader who cannot reconcile your flaring stops trusting your Scope 3.
Build the reconciliation as part of the process rather than in response to a question. It is far cheaper to construct while the data is fresh.
The single most common boundary error in this sector, and one that materially changes the reported number.
If you export refined products, petrochemicals or fertiliser into the EU, CBAM may reach you through your buyer before any Nigerian mandate reaches you — and the data it requires is different in kind. CBAM asks for emissions embedded per unit of product from a specific installation, not organisational totals.
The underlying measurement is the same measurement. What differs is the allocation: you need process emissions attributable to a production route and a product, with a documented basis. If you are already measuring at installation level for your own disclosure, the additional work is allocation rather than metering.
Disclose the values you used and their source. Most reporters use the values from the most recent IPCC assessment available at the reporting date, on a 100-year basis, with some also disclosing a 20-year basis given methane’s short-lived, high-intensity profile. Consistency and disclosure matter more than the choice.
If it is material — and for a hydrocarbon producer it almost certainly is — then yes, or you must explain the exclusion. Omitting the largest category in your value chain without explanation is the most visible possible gap in an oil and gas disclosure.
Yes, with the method disclosed and the estimation uncertainty described. Engineering estimates and emission factor approaches are standard practice in this sector. What is not acceptable is a precise-looking figure with no stated basis.
Nigeria’s Climate Change Act 2021 establishes a national framework including carbon budgets and gives the National Council on Climate Change a mandate that reaches large emitters. Its interaction with sector-specific obligations continues to develop — take current advice rather than relying on a summary.
A summary of a regulation is not the regulation. These are the primary documents this page is based on.
Four questions, and you get the year you first file, the framework, and what to collect first.
Plain-language explainers of the FRC and SEC rules, ISSB S1 & S2, and what each asks you to disclose.
What a consultant-led reporting cycle costs against an annual licence, in Naira.
