Global upstream investment is holding steady under sustained price pressure — then the Iran war broke out and changed the calculus overnight. As North American shale matures and majors retrench, Latin America is emerging as the decade's most compelling frontier for disciplined capital. Here is what the data says, and what it means for asset owners.
The upstream sector entered 2026 in a posture it has maintained for several years: capital discipline as a core operating principle. Following the boom-bust cycles of the 2010s, operators learned to prioritise free cash flow over production growth, and that instinct had not changed — even as the macro environment became more hostile.
Oil prices drifted lower through 2025 and into early 2026. WTI spent much of the pre-war period in the low-to-mid $60s per barrel, with independent forecasters projecting a range of $50–$65 through the year — a meaningful step down from the $70+ range operators had been expecting at the start of 2025. The culprit was straightforward: global supply growth outpacing demand, with OPEC+ production discipline eroding at the margin and US output continuing to set records above 13.6 million barrels per day.
Natural gas told a different story. Henry Hub averaged well above $3.50/MMBtu through H1 2026 — a dramatic recovery from the sub-$2 levels of 2024 — driven by LNG export demand and a colder-than-average northern hemisphere winter. Over 90 bcm/year of new LNG liquefaction capacity reached FID in 2025, with the United States accounting for the majority. Gas-weighted portfolios were performing considerably better than oil-heavy ones going into the conflict.
Major international oil companies responded to the price weakness predictably. Overall capex from the largest players declined 3–5% from 2025 levels, with portfolio restructuring accelerating. Nearly 70% of listed US oil and gas companies actively divested non-core assets, and asset-level M&A accounted for nearly half of all deal value.
"The companies winning in this environment are not those chasing production — they are those who have optimised their existing assets hard enough to generate free cash at $55 oil."
Digital and AI adoption accelerated sharply in this context. What began as pilot programmes moved to enterprise-wide deployment: AI-driven predictive maintenance, IoT-enabled production optimisation, digital twin modelling of asset behaviour. These are not aspirational technologies — they are becoming competitive necessities as shale productivity gains flatten and mature fields require more intelligent management to sustain output.
On 28 February 2026, Operation Epic Fury — the joint US-Israel campaign against Iran — triggered the largest oil supply disruption in the history of the global market. The effects are still reverberating. This section updates our original analysis in light of these events.
When the US-Israel coalition struck Iran in late February 2026, the entire framework of oil price expectations for the year was rewritten within days. Iran moved immediately to restrict traffic through the Strait of Hormuz — the narrow passage through which approximately 20 million barrels per day of crude and petroleum products normally flow, representing roughly one-fifth of global supply. The IEA described the resulting disruption as "the largest supply disruption in the history of the global oil market."
The price sequence was dramatic. Brent surged 10–13% within the first 72 hours, reaching $80–82/bbl by 2 March 2026. When Qatar announced that Iranian drone strikes had halted all gas production at its facilities and QatarEnergy declared force majeure, markets moved sharply again. By mid-March, with the Hormuz closure now effectively total, Brent crossed $120 per barrel — levels not seen since the post-Ukraine spike of 2022. Some analysts forecast $150 if disruptions persisted.
The implications for the upstream sector are significant and still unfolding. In the near term, the price surge delivered a windfall to producers outside the Gulf — US, Brazilian, and Latin American operators with no Hormuz exposure saw margins expand sharply. For asset owners with producing fields, the crisis demonstrated exactly why low-cost, low-geopolitical-risk production in the Western Hemisphere commands a structural premium that the market had perhaps under-appreciated in the drift toward $60 oil.
For gas, the war supercharged an already constructive picture. European buyers scrambled to replace disrupted LNG flows from Qatar and moved aggressively to secure alternative supply. US LNG exports hit new records. TTF gas prices that had been expected to moderate instead surged again — and operators with Atlantic-basin LNG exposure are now looking at a demand backdrop that exceeds even the most optimistic pre-war projections. For Argentina's Vaca Muerta and Brazil's deepwater gas ambitions, the war has pulled forward the development case by years.
"The Iran war did not just spike the oil price — it exposed which assets are structurally insulated from geopolitical risk, and which are not. Latin America's answer to that question is compelling."
The medium-term uncertainty is substantial. Even with the ceasefire nominally holding, tanker traffic through the Strait remains severely disrupted. Analysts at CEPR estimate that even under an optimistic scenario — Hormuz closed for one quarter, gradual resumption thereafter — US headline inflation rises 0.6 percentage points in 2026. For operators planning capital programmes, the price deck assumptions made in late 2025 are materially different from the world being navigated today.
When capital is disciplined and price assumptions must account for both downside risk and supply-shock upside, investors ask a simple question: where can I find low-cost, near-term production with a credible development pathway and minimal Hormuz exposure? In 2026, that question points with increasing frequency to Latin America — and the Iran war has sharpened the focus considerably.
The region is not a single investment thesis — it is a patchwork of very different stories at different stages of maturity. But taken together, Latin America is the only region currently capable of delivering meaningful incremental supply over the next decade at breakeven prices that work in a $60–$80 world, with no structural dependence on Middle East transit routes. That combination is rare, and the market is recognising it with urgency it lacked six months ago.
Brazil is the anchor. Petrobras hit 5.3 million boe/day in February 2026 — a 16% year-on-year increase — and the company's pre-salt breakeven prices have fallen to levels that compete with the best conventional basins anywhere on earth. A five-year, $109 billion investment plan runs through 2030, with $78 billion directed to upstream. The April 2026 FID for the Sergipe Águas Profundas deepwater gas project — a $6 billion development — signals that the frontier is still yielding material new resources even as the basin matures.
Argentina has arguably been 2026's most significant upstream story, and the Iran war has only reinforced its strategic value. The Vaca Muerta shale formation now accounts for nearly 70% of the country's oil output and 65% of gas production, and it is growing fast. Milei's Large Investment Incentives Regime (RIGI) has unlocked capital that was previously sitting on the sidelines: YPF is spending $5.6 billion this year, $4.5 billion of it upstream. The first RIGI-approved LNG export project — a 6 MTPA floating terminal — is now being evaluated in the context of a European gas market willing to pay significant premiums for non-Middle East supply. The Vaca Muerta Sur pipeline Phase 1, due for completion in Q3 2026, will enable evacuation of 190,000 barrels per day.
Guyana remains the world's most compelling emerging producer. The Stabroek Block — 11 billion barrels and counting — is being developed at pace, with the Uaru project expected to begin production in 2026. The constraint is no longer geology; it is national execution capacity, port infrastructure, and skilled labour availability. For service providers and technical advisors, that is the opportunity.
Venezuela represents a separate chapter. Investor delegations are returning to Caracas, and major operators are beginning to re-evaluate assets in what remains one of the world's largest resource bases. But the investment case carries serious caveats: infrastructure that would require $100–250 billion to restore to pre-1999 capacity, regulatory opacity, and political risk that even the most optimistic analysis cannot easily discount. Venezuela is no longer off-limits for serious evaluation — but it is a long way from being a near-term production story.
Several implications follow directly from the conditions described above — and the Iran war has sharpened each of them.
Western Hemisphere production is now priced differently. The war has crystallised something investors had understood abstractly but not yet priced fully: assets outside the Middle East and outside the Hormuz transit risk zone carry a structural premium that is now visible in deal pricing, in financing terms, and in operator strategy. Latin American upstream assets with demonstrable production and credible reserves are trading in a materially different market than they were in January 2026.
Existing production is worth more than it was. In a volatile, capital-disciplined environment, the premium on well-performing producing assets increases further. Operators with fields generating reliable cash at $60–80 oil are not looking to sell — they are looking to optimise. The demand for rigorous, physics-based production surveillance, artificial lift optimisation, and decline mitigation work is higher than it has been in several years.
The evaluation bottleneck is real. Capital is available for Latin American upstream assets, and the Iran war has accelerated flows of that capital into the region. But the pipeline of credible, independently evaluated opportunities is not keeping pace with investor appetite. Deals are being delayed or mispriced not because of a lack of interest but because of a lack of rigorous technical work. Petrophysical evaluation, volumetric uncertainty quantification, decline analysis, and economics that genuinely integrate subsurface risk — these are the disciplines that unlock transactions.
"Capital is available. The bottleneck is not money — it is the technical credibility that turns an asset into a fundable opportunity."
The gas story deserves more attention than it is getting. European buyers, burned twice now by dependence on unreliable supply corridors, are actively seeking long-term LNG offtake agreements from Atlantic-basin producers. Upstream gas development in Latin America — whether Vaca Muerta unconventional, Brazilian deepwater, or Colombian offshore — is being driven by a combination of domestic power demand and LNG export ambitions that is now structurally underwritten by a European market with an urgent need to diversify.
Digital tools are changing the standard of evidence. In competitive asset processes, the quality of reservoir modelling and production forecasting presented to buyers and investors is shifting. Operators who can demonstrate real-time production surveillance, history-matched models, and transparently constructed economics are commanding better terms than those who cannot. The bar for "good enough" technical work is rising.
Our philosophy has always been that the asset is a closed loop: reservoir, wells, facilities, and export must be optimised together against a single objective — profit — and that the model is the primary tool for doing that. The current market environment makes that philosophy more relevant, not less.
In a world where oil prices have ranged from $60 to $120 within a single calendar year, there is no room for the inefficiencies that come from evaluating reservoir performance independently of production system performance, or from modelling economics that do not genuinely reflect subsurface uncertainty. The assets that generate returns through this kind of volatility will be those whose owners understand them completely — and can demonstrate that understanding to capital providers across a wide range of price scenarios.
Latin America is where we operate, and we are encouraged by what we see: capital returning to the region with renewed urgency, governments competing for investment with credible fiscal frameworks, and a generation of producing assets that are well-placed for the optimisation work that this stage of the cycle demands. The Iran war has accelerated that opportunity. The technical work required to realise it is precisely what we exist to do.
Whether you need a quick-look evaluation, a full field model, or a costed scope of work for a portfolio of assets — use the Plan Your Job configurator to define the work and get an indicative timeline and cost before you commit.
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