Head of Commodity Strategy
The oil market is entering 2026 with an unusual mix of short-term comfort and long-term unease. On the surface, supply looks ample. Inventories have risen, demand growth has cooled, and parts of the curve trade with enough softness to keep macro-focused traders relaxed. But beneath that veneer sits a deeper structural tension that has only grown clearer over recent months: the world still needs large volumes of new oil supply well into the coming decades, and current price levels are probably not sufficient to incentivise it.
This tension is visible already in how the market is treating next year’s supposed surplus. The IEA’s projection of a potential 4 mb/d oversupply in 2026 has stirred debate, but it remains hard to find evidence of such a large overhang in actual market pricing. A genuine glut would normally force the futures curve into a deep contango, boost storage economics and generate visible stock buildups across major hubs. For now, the curve remains relatively flat, not flipping into a contango until October next year, suggesting that while Q1 may feel heavy as the market digests the inventory overhang built in late 2025, it is not pricing a structural oversupply. In other words, a soft patch is likely, but not a repeat of the 2020–21 imbalance.
The more consequential development is the IEA’s important shift on demand. Only a few quarters ago, the agency frequently emphasised scenarios where oil demand peaked before 2030. Its latest long-term outlook is a clear departure from that thinking: absent highly aggressive policy changes, global oil demand is now projected to keep rising well beyond 2040 and potentially approaching 2050. The revision is material, because it forces the market to reconcile two competing facts: the world is still consuming around 102–103 mb/d, and existing fields are declining at a relentless pace of 6–8 mb/d each year.
That depletion rate is the most powerful force in the market, and easily the least appreciated. It effectively means the global industry must replace a “new Saudi Arabia” every couple of years just to hold production steady. When viewed through that lens, the notion of a future surplus looks increasingly fragile. In essence, the IEA sees a massive and rapid drop in supply by the early 2030s if the industry fails to invest an estimated $500 billion per year just to maintain current output levels. That gap is the core of the long-term price story: unless the market rewards investment today, it will be forced to cope with scarcity tomorrow.
Spare capacity offers only limited reassurance. Saudi Arabia and the UAE remain the only major producers able to raise output at short notice, and both are now operating closer to their expanded capacity levels, naturally reducing the available buffer. The market’s real vulnerability emerges if non‑OPEC+ production slows, particularly in the Americas. Brazil and Guyana have been important growth engines, but their expansion profiles will eventually mature, while US shale output—resilient at around 10.6 mb/d—is beginning to show signs of levelling off.
That matters because shale has functioned as the world’s “just-in-time” supplier for a decade. If it loses that role, the entire system becomes more reliant on a narrow set of producers—and therefore more sensitive to price signals. Growth of roughly 360 kb/d over the past year is unlikely to be repeated, with the U.S. Energy Information Administration expecting total US production to flatten in 2026 and potentially in my opinion decline should WTI spend another year below USD 60.
The so-called wildcards—Iran, Russia and Venezuela—do little to ease the picture. Russia is constrained by sanctions, technology access and declining upstream productivity. Venezuela has vast resources but lacks the infrastructure, political stability and capital to restore production meaningfully in the near term. Iran is the only producer with measurable upside, having demonstrated output near 3.8 mb/d in the past versus around 3.4 mb/d today. Even if it regained that capacity, the additional volumes would be marginal relative to the annual depletion rate, not to mention the medium-term demand outlook.
Taken together, these dynamics frame 2026 not as a year of surplus comfort, but as a year where the seeds of future tightness are planted. A temporary dip in prices would not be surprising in Q1, but it would represent short-term noise rather than long-term equilibrium. The structural reality is simple: the world will require sustained investment to prevent a supply crunch in the early 2030s, and that investment only materialises if prices remain high enough to justify long-cycle commitments.
The market must therefore choose between two paths. It can allow prices to firm gradually—supporting the drilling, upstream expansion and long‑cycle projects required over the coming decade—or it can risk far sharper price increases later as scarcity becomes the dominant driver. Even with a short‑term overhang, deferring investment only amplifies future tightness. The core message is not that a surplus looms in 2026, but that meeting future demand requires a sustainably higher price environment. The earlier that price signal appears, the lower the eventual peak is likely to be. A disorderly surge in crude prices benefits no one, especially producers depending on crude production as their main revenue generator as it accelerates the shift toward alternatives, tightens financial conditions and risks renewed inflation alongside slower growth.
For investors looking to position for structurally higher crude, the integrated oil majors remain the most direct and liquid route. The sector continues to trade at modest valuations relative to broader equity markets, with earnings multiples still discounting a world where long‑term oil demand stagnates. The IEA’s shift away from early peak‑demand narratives challenges that assumption, and the combination of low valuations and strong free cash flow makes the majors natural beneficiaries of a firmer price environment.
The five largest integrated producers—ExxonMobil, Chevron, Shell, BP and TotalEnergies—offer diversified exposure across upstream, downstream and low‑carbon assets. Their upstream operations provide leverage to rising crude, while refining and marketing divisions help stabilise earnings. With disciplined capex and an emphasis on dividends and buybacks, these companies are well‑positioned if crude prices strengthen in line with the structural outlook.
For broader exposure, investors can consider energy‑focused ETFs. XLE and IOGP provide large‑cap integrated and upstream coverage, while XOP offers a higher‑beta alternative via exploration and production companies. These instruments offer diversified, liquid exposure to a sector that remains attractively priced relative to both historical norms and other commodity‑linked industries.
If the market shifts toward a higher and more durable price regime—as supply‑demand fundamentals suggest—the energy equity complex offers a balanced way to participate, combining income with leverage to a structurally tighter crude market.
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