The 'methane fee', a part of the amended text of the Build Back Better Act released by the House Rules Committee in the US, could cost the petroleum and natural gas industry $1.3 billion in 2025 under a status quo scenario, a Rystad Energy analysis shows. Although the latest draft bill relaxes some of the previously proposed regulations, the latest iteration will still have a profound economic impact, especially on smaller onshore producers. Even though the proposed bill would go into effect in 2023, the phased introduction — 60% in 2023, 80% in 2024 and 100% in 2025 — means the full effect would not be felt until the middle of the decade. The $1.3 billion estimated cost impact in 2025 assumes producers continue output and methane intensity at 2019-2020 levels on average. Methane intensity is — however — improving quickly. "The actual impact in 2025 will be south of $1 billion based on base case production growth and expected improvements in methane intensity. It is important to point out that the real impact will be biased even more towards smaller producers and conventional legacy fields in contrast to what the current status quo suggests," said Artem Abramov, head of shale research at Rystad Energy. Methane intensity is improving quickly for most companies based on the Subpart W accounting methodology, so by 2025 many key producers will all be under the intensity thresholds proposed in the latest version. On the other hand, the Environmental Protection Agency (EPA) still has a plan to decrease the Subpart W reporting threshold from 25,000 to 10,000 tons CO2e per year. If implemented, we will see a larger number of smaller producers included in the methane fee calculation and they typically have higher methane intensity levels than their larger peers. "Despite its impact — and when compared to the original methane bill introduced in March 2021— the revised methane fee is a much softer proposal that introduces arguably a more justified formula for calculation," Abramov added. Small producers may pay the cost To understand the potential economic implications for the industry, it is important to consider how the sector has been progressing in methane intensity — the ratio of methane emissions to natural gas produced — as per the Subpart W reporting standards. Recent history shows the industry has steadily improved its methane intensity since 2016, especially the bigger producers. Rystad Energy analysis estimates only $7.5 million in annual costs per operator for large producers — roughly the equivalent of drilling one 2-mile long horizontal well in the Midland Basin today. If we convert these numbers into variable incremental costs or normalize to production levels, the average impact is only four cents per barrel of oil equivalent (boe), on a gross operated three-stream basis, with only a handful of large producers seeing an impact above 10 cents per boe, based on their 2019-2020 performance. Hence, going by the steady methane intensity improvements the industry was able to deliver between 2016 and 2020, it will be no surprise if most large operators fall below the minimum emissions in the first year of the new rule. For this reason, we predict the number of key oil & gas producers that will be subject to the proposed fee – those with methane intensity levels above the allowed thresholds of 0.2% for production and 0.05% for gathering & boosting (G&B) — will be relatively low. Thus, even in a status quo scenario, where the industry's performance holds as is, the annual $1.3 billion methane fee will largely be borne by smaller producers, who will still qualify for reporting requirements under Subpart W. If the EPA extends the reporting requirement of the methane fee plan and lowers the threshold from 25,000 to 10,000 tons CO2e per year, the annual impact on the industry would exceed $1 billion even in a scenario where performance improves continuously. In such a case, the proposal's economic impact will be biased even more towards smaller producers. Breaking down emissions The breakdown of methane emissions into G&B and production is critical to quantify the theoretical impact of the fee for oil & gas operators as the allowed methane intensity thresholds in the proposal are different — 0.2% for production and 0.05% for G&B. Although excluding the G&B segment will not significantly impact many operators' methane intensity, in cases where the intensity of production is lower than the ratio of total Scope 1 methane emissions compared with gross operated production, the G&B segment will account for a large share of total emissions. This is particularly the case for several large and mid-sized oil-focused producers. — Rystad Energy
