Energy: From market shock to the re-hierarchization of projects and capital
Summary
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- Hormuz is not just a price shock: it’s a security of supply stress test. When geopolitical risk materializes, decision-makers rethink robustness, and this can re-prioritize projects and redistribute capex. Home-grown risk is likely to take a long-term hold on investment decisions.
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- Liquefied natural gas: The crisis is not mechanically reviving a wave of greenfield LNG projects; it is re-hierarchizing them. The winners are executable developments, backed by existing facilities and located in geographies perceived as more neutral or diversifying, while long, complex projects remain penalized by execution risk. For investors, this means faster investment decisions on certain projects and, mechanically, closer financing requirements, particularly in the emerging markets of West Africa and Latin America.
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- Oil : the combination of the Hormuz shock (security of supply premium) and shareholder pressure to renew reserves may help reopen an exploration cycle outside the Middle East to secure a portfolio of projects beyond 2030 – particularly in the Atlantic Basin, which offers attractive economics and appears to be one of the natural substitutes for the Middle East.
Introduction
The scale of the current crisis goes beyond that of a simple geopolitical episode: it combines logistical disruption, military risk and energy tension – to the point of reminding many observers of a superposition of past crises, from the oil shocks of the 1970s to the gas crisis of 2022.
Above all, this crisis is not just a flow shock or a succession of temporarily closed wells. In some places, it is taking the form of an asset shock: physical infrastructures affected, capacities degraded, and therefore a potentially lasting unavailability of certain key elements of the energy system. This reading was explicitly reinforced by the IEA President’s statement on March 23 that at least 40 energy assets in the Middle East had been severely or very severely affected – a signal that immediately shifts the analysis from the field of short-term prices to that of capacities, their re-commissioning and hence investment decisions.
So the challenge goes beyond short-term volatility: if the crisis also materializes in assets, it may lead us to reclassify projects, re-price risk and redeploy capital in a different way.
Against this backdrop, one question stands out in particular for long-term investors with exposure to energy chains, such as IVO Capital: how can this crisis reshape capex allocation, especially in the energy sector in emerging markets?
LNG: where the crisis becomes structural: no longer a flow shock but an asset shock
For the time being, LNG (liquefied natural gas) appears to be the segment with the most structuring impact, since the crisis is not limited to a flow shock: it takes the form of an asset shock (capacity unavailable for years) coupled with a logistical shock. The most significant and best quantified asset shock at this stage is that of Ras Laffan, the heart of Qatar’s LNG system: damage to the liquefaction trains represents around 12.8 million tonnes per year (~17% of Qatar’s exports), with a repair horizon of 3 to 5 years and a long-term force majeure risk. This asset shock removes material capacity from the market over several years.
In addition to this “asset” dimension, LNG has its own rigidity: unlike oil, there are few bypass solutions. LNG is difficult to substitute logistically, and storage capacity remains much more constrained, reinforcing the asymmetry of the shock in the event of prolonged disruption.
Beyond the immediate market shock, war can therefore reshape investment decisions. It acts as an energy security stress test: when geopolitical risk materializes, buyers and investors no longer think in terms of price alone, but reassess the robustness of supply chains and dependence on certain zones deemed more fragile. In this context, the global LNG map is likely to be re-priced due to the risk of concentration: in the event of a disruption to Hormuz, the LNG volumes at risk include ~106 Bcm/year (Bcm: billion cubic meters) for Qatar alone (i.e. ~16% of the global market), plus ~7 Bcm/year for the Emirates. This dependence is all the more sensitive as it is channeled through a single bottleneck: over the last twelve months (March 2025 to February 2026), Qatar and the UAE are estimated to have exported 115.5 Bcm, of which 108.4 Bcm actually transited through the Strait of Hormuz. In other words, the physical origin of supply should become key. And it’s not just about Hormuz, it’s the geopolitical concentration of the world’s LNG today that’s becoming a real issue. Global LNG supply is extraordinarily concentrated on three geopolitically sensitive poles (the USA, Qatar and Russia) (see below).
Source: Pareto Securities
Post-Iran, LNG investment decisions should therefore be increasingly guided by basin-wide resilience. In practical terms, this will restore the value of projects outside these blocks, particularly in geographies perceived as more neutral or diversifying, and in particular African or Latin American projects currently maturing with considerable resources, notably in West Africa or Argentina. and, more broadly, to projects that are less justified in a strictly “price only” world, but which become relevant again in a more fragmented world where security of supply is paramount. These basins are home to some of the world’s largest gas reserves (West Africa ~240 TCF, Argentina alone ~300 TCF). As an order of magnitude, the African and Latin American basins alone represent several thousand million tonnes of potentially monetizable LNG, more than enough to supply several decades of European demand. These volumes are not new, but they were marginalized in a world dominated by American and Qatari mega-projects. The materialization of geopolitical risk is now acting as a catalyst, revaluing resource-rich but historically under-invested basins.
Please note: Ormuz will not trigger a wave of complex greenfield projects overnight. Rather, the crisis acts as a filter: it favors executable investments, already structured and backed by existing infrastructure, which can be completed in shorter timeframes (2-3 years) than mega-greenfield projects (5-7 years), which remain constrained by long cycles, industrial lead times and greater execution risks.
In this context, the winners in our emerging geographies are mainly :
– Expansions / additional phaseswhich maximize the use of existing assets and reduce execution risk;
– And fast-track solutions (such as FLNG – floating LNG units), which enable resources to be monetized more quickly by limiting some of the onshore constraints.
This logic is already materializing in our emerging universe, notably in the Atlantic basin. In Angola, the New Gas Consortium (NGC) – operated by Azule Energy (JV 50/50 bp/Eni) – has started gas production at Quiluma in March 2026, according to a typically “executable” scheme: offshore shallow-water gas, onshore processing, then supply to the existing but under-utilized Angola LNG plant.
Conversely, Tortue Phase 2 (bp/Kosmos) in Senegal/Mauritania is progressing more slowly, but its design logic is precisely that which can be “reactivated” in a context of re-rating security of supply: a capital-efficient expansion that maximizes the use of Phase 1 infrastructures.
In the same spirit, independent operator Trident illustrates a “fast-track” option in gas, with a development project favoring a FLNG solution in Congo, an investment project that could be sanctioned as early as this year in the current context.
The crisis is not mechanically reviving a wave of greenfield LNG projects; it is re-hierarchizing them. The winners are executable developments, based on existing facilities and located in geographies perceived as more neutral or diversifying, while long, complex projects continue to be penalized by execution risk. For investors, this means faster investment decisions on certain projects and, mechanically, closer financing requirements, particularly in the emerging markets of West Africa and Latin America.
Oil: distinguishing short-term redistribution from long-term reconfiguration
For oil, the impact of Hormuz is massive, but of a different nature to that observed for LNG. The shock is primarily logistical: production capacity has not “disappeared”, and a resumption of flows is still conceivable if transit and insurance conditions normalize. Unlike LNG, this shock is partially cushioned by more important flexibility mechanisms: rerouting capacities (limited but not zero), mobilizable stocks and strategic reserves, which can act as a short-term cushion (see below).
Source: J.P. Morgan Commodities Research
In this environment, it is still possible to identify beneficiaries, provided we distinguish between the redistribution of short-term investments and that which takes place over the long term.
In the short term, the winners are those with the capacity to rapidly adjust capex and volumes: US shale first, then international shale – notably Argentina (Vaca Muerta) – as well as certain mature conventional zones where optimization (infill, workovers, tie-backs) can add barrels without requiring heavy infrastructure (Colombia, Ghana, Angola, Equatorial Guinea).
In the long term, the re-pricing of security of supply may favor hubs offering both cost-competitiveness and logistical resilience. In this context, the Atlantic Basin – in particular Brazil, Guyana and, on the African side, certain deepwater margins (e.g. Namibia, Côte d’Ivoire) – stands out as a natural candidate: it concentrates an increasing share of deepwater growth and remains a structural pole for offshore expansion. And, as the operating cost curve to 2030 shows, Brazil/Guyana are among the most competitive segments outside the Middle East.
Cost and volume of oil production to 2030 by production zone
Source: Rystad Energy
A recent note from J.P. Morgan reminds us that, while the medium-term supply trajectory (to 2028-2029) is based on projects already identified in this Atlantic basin, visibility beyond 2030 is becoming more conditional as it depends more on new discoveries, which could put exploration back at the center of the stakes in this basin.
This dynamic is reinforced by a factor that has once again become central to the governance of the majors: pressure from shareholders to clarify growth plans and the trajectory of reserve renewal. The Financial Times has pointed out that, after years dominated by financial discipline and shareholder returns, the majors are increasingly being questioned about the longevity of their reserves and the soundness of their project pipeline. This angle is also apparent in our discussions with companies in the sector.
In practice, the combination of the Hormuz shock (security of supply premium) and shareholder pressure to renew reserves may help reopen an exploration cycle outside the Middle East to secure a portfolio of projects beyond 2030 – particularly in the Atlantic Basin, which offers attractive economics and appears to be one of the natural substitutes for the Middle East.
And what about renewable energy?
Beyond oil and gas, the current crisis may also play into the hands of renewables. In many markets, the wholesale price of electricity is determined by the marginal power plant needed to balance the system – often a gas (and sometimes coal) unit, whose production cost varies directly with the price of the fuel. In this context, a rise in gas/coal prices tends to push up the price of electricity, while the variable production cost of renewables (wind/solar) remains low. This improvement in project economics can, in the long term, support investment: it strengthens bankability (ability to secure financing) and facilitates the signing of long-term contracts (PPA) in a context where security of supply is once again a priority.
Positioning of the IVO EM Corporate Debt fund
The IVO EMCD fund aims to capture these dynamics in emerging markets and adapt to market changes.
The IVO EMCD fund is positioned to capture the “security of supply” re-rating in emerging markets through exposure to LNG assets outside the Middle East.
This translates firstly into exposure to industrial liquefaction infrastructures outside the Middle East, such as Peru LNG (2nd position in the fund as at 25/03/2026). The fund is also positioned in EM producers with gas assets and/or stakes in associated infrastructure, such as Azule Energy (5th position in the fund). We also monitor and invest in FLNG infrastructure providers and producers with options for monetizing gas via FLNG in Africa, such as Trident Energy (6th position in the fund).
Finally, we also like to gain exposure to the growth cycle in offshore production in Brazil and Guyana, by focusing on players in the supply chain (services & infrastructure) with high visibility on their order books. This exposure is generally less sensitive to Brent: it is primarily driven by volume growth with project visibility up to ~2030, and the continuity of investment programs in highly competitive basins, whose economics remain attractive even in a lower price scenario.
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