How Fiscal Incentives Can Turn Mexico’s Flared Gas Into Revenue

Mexican oil fields release enough natural gas into the atmosphere to supply a midsized industrial city. PEMEX's second-quarter 2026 disclosures show the country flared and vented an average of 778 million cubic feet per day (MMcf/d) — around one-fifth of total gas production. Reducing flaring is a huge technical and financial challenge for a single company that is financially constrained and has legacy fields with outdated infrastructure. However, if Mexico frames this problem as an underused national asset, the Ministry of Finance and Public Credit (SHCP) and Ministry of Energy (SENER) could convert this wasted gas into revenue, jobs, and cleaner air without requiring public investment.  

Over the past decade, several oil-producing countries have made real progress on reducing flaring and methane, and their experience offers two distinct paths — one of which fits Mexico's current fiscal reality far better than the other.

Two Roads Other Countries Have Taken

Successful reducers have generally followed one of two models. The regulatory model relies on binding mandates — leak detection, bans on routine flaring, continuous monitoring — enforced with penalties; it works, but is capital-intensive.  A second model, via fiscal incentives, instead changes the economics so capturing gas is more profitable than burning it: the government adjusts a tax, duty, or price, and private capital does the rest.

Canada, Kazakhstan: Effective But Capital-Intensive

Canada is the textbook case of the regulatory path. Ottawa's methane rules — introduced in 2018, tightened in regulations finalized in late 2025 — target a 75% cut in oil-and-gas methane emissions by 2030 versus 2012 levels. Environment and Climate Change Canada calls the finalized rules one of the lowest-cost ways to cut greenhouse gases anywhere, at roughly US$34 per ton of CO2-equivalent, with a net economic benefit of about US$17 billion (figures converted from Canadian dollars at the applicable historical exchange rate and expressed in constant 2025 US dollars). That sits atop a large upfront bill, industry's own 2018 estimate for its broader climate-compliance burden translates to close to US$24.7 billion over ten years. Compliance for existing facilities doesn't fully kick in until 2028, precisely because operators needed years to finance the retrofits.

Kazakhstan tells a similar story. Routine flaring has been banned since the mid-2000s, and the country cut flared volumes by more than 70% between 2012 and 2022 — the largest reduction of any producer in that period — underwritten by the deep pockets of the international majors operating its largest fields (Chevron, Eni, Shell, and partners at Tengiz, Karachaganak, and Kashagan), paired with a domestic gas market built to make associated-gas recovery pay for itself.

Mexico already has a comparable mandate which makes the lesson sharper. Since 2016 all operators — state and private — must sustain at least 98% utilization of associated natural gas. Private operators, largely running newer fields with modern gas-handling infrastructure, have stayed close to that standard. PEMEX's aging, high-volume assets account for most of the shortfall: the flagship Ku-Maloob-Zaap complex, the country's top crude producer, utilized only 66–74% of its associated gas as of the most recent compliance data, and Pemex's 2026 disclosures show flaring and venting have since nearly doubled. Enforcing the mandate more strictly would therefore not spread costs evenly across the industry the way Canada's rules do — it would land almost entirely on Pemex, straining a company that already carries a heavy debt load. 

In both Canada and Kazakhstan, several corporations with significant available capital carried the upfront cost but in Mexico a stricter mandate would concentrate the cost on Pemex, which would conflict with paying debtholders or suppliers.  This is why a more actionable opportunity lies in the second model relying on incentives.

The United States and Argentina: Private Capital Does the Work

The incentive-based path asks for far less public money. Texas's House Bill 591 (2023) exempts operators from severance tax on gas that would otherwise be legally flared or vented, provided it is captured and consumed on-site — a rule that has drawn private investment in modular power and data-center/bitcoin-mining units built at the wellhead. Wyoming passed a similar exemption in 2021, and a 2025 federal proposal (the FLARE Act) would extend permanent full expensing to flare-capture equipment nationwide. Neither exemption costs the treasury revenue it was already collecting, because flared gas has never generated tax in the first place. Since it isn't sold or put to use, Texas and Wyoming both treat flared gas as having no value for severance-tax purposes. Capturing that same gas and using it on-site changes its tax status, though: absent an exemption, gas that is produced and consumed — to run a generator, power a data center, or anything else — is normally a taxable event under severance tax law. In other words, before these laws, flaring was tax-free by default and capturing was the choice that risked a tax bill. The enacted regulation simply put captured gas on the same $0 footing as flared gas, removing the one asymmetry that made continuing to flare the path of least resistance.

Argentina offers a parallel example at a larger scale. Its 2024 RIGI investment regime — reduced corporate tax, exemptions from new taxes and import duties, currency-exchange flexibility — has pulled billions into Vaca Muerta's shale gas fields, where private firms also now capture gas that would otherwise be flared to power data centers and bitcoin-mining operations, turning a liability into jobs and tax revenue on private balance sheets. Nigeria's Gas Flare Commercialization Program, auctioning flared-gas rights to private investors, is projected to attract up to US$7 billion in investment without requiring state capital.

The institutional groundwork for this second path already exists. SENER already controls permitting and access; SHCP already has a recent precedent for adjusting fiscal terms; the legal basis for private participation already exists. What's missing is one specific, joint decision on a Price Committee: a preferential natural gas price for volumes that would otherwise be flared, paired with a transparent access mechanism — modeled on Nigeria's auctions or a tailored volumetric price, incentivizing private investors build small and mid-scale capture infrastructure, virtual pipelines (CNG trucked to nearby industrial users), gas-to-power microplants, or data-center colocation at flare sites.

Increased Revenue That SHCP Could Generate

Consider just half of what is currently flared and vented could be easily captured. At the 2Q26 rate of 778 MMcf/d, 50% is 389 MMcf/d — annualized, about 142 billion cubic feet, or roughly 147 million MMBtu at the standard industry conversion factor. Sold at a conservative US$1.0/MMBtu, that volume alone would generate roughly US$150 million per year, close to MX$2.5 billion, for gas the treasury currently collects nothing on. That's before the corporate and payroll tax revenue generated by the private infrastructure built to capture and deliver it.

What's at Stake for the Country

1) For SHCP: new fiscal revenue without requiring new debt to fund capital investments.

2) For SENER: Decarbonization progress and energy security. Every cubic foot captured instead of flared chips away at the import dependency from the US and strengthens Mexico's sovereignty.

3) Lower emissions and local pollution. Captured gas cuts methane — roughly 80 times more potent than CO2 over 20 years — plus the sulfur oxides and particulates affecting communities near fields in Tabasco, Veracruz, and Campeche.

4) Jobs. Gas gathering, compression, virtual-pipeline logistics, CO2 injection for secondary recovery projects, small-scale power generation, gas to ammonia and data-center operations are examples of viable projects that private companies would finance, staff and execute.