The major national oil companies of the Gulf are deploying significant billions of dollars to decarbonize their production without reducing its volumes. This bet rests on a conviction: according to scenarios, oil and gas retain an important role, but their weight and trajectory diverge sharply by 2050. A rapid decline in oil demand would increase the commercial risk of certain projects, without demonstrating that CCUS and blue hydrogen assets would become unusable.

The essentials

  • Gulf national companies are investing significant billions of dollars to reduce the carbon footprint of their production, not its volumes (DNV Energy Transition Outlook 2026).
  • Carbon capture and storage (CCUS) and blue hydrogen are experiencing growth in the region across a significant number of identified projects.
  • Saudi Arabia aims to be a major producer-exporter of clean hydrogen and the UAE targets a high global rank, without an official joint target of the world’s leading exporter by 2060.
  • In the IEA’s STEPS scenario, oil demand plateaus around 102 mb/d toward 2030 before declining slowly; in a very reduced demand scenario, a significant portion of these investments risked becoming stranded assets.
  • The strategy combines the maintenance and expansion of hydrocarbons with CCUS, hydrogen, and investments in renewables.

Decarbonizing without reducing: the logic of the double bet

Understanding the Gulf’s strategy requires abandoning a common assumption: that decarbonizing means producing fewer hydrocarbons. For Saudi Aramco, ADNOC (Abu Dhabi), or QatarEnergy, the equation is different. They want to produce as much, or more, but with significantly reduced carbon intensity per barrel. Carbon competitiveness is a stated objective among others, within a strategy that also includes renewable energy and hydrogen activities.

This distinction changes everything when reading the figures. A significant share of these investments does not go toward wind farms or solar panels. They finance carbon capture and storage (CCUS), electrification of oil facilities from less-emitting sources, and production of so-called “blue” hydrogen: hydrogen made from natural gas, with capture of the CO₂ emitted during the process. The idea is to sell, tomorrow, hydrogen less carbon-intensive than that produced today by industrial economies that simply burn gas without capture.

Announcements of growth for 2026-2030 signal an ambition for deployment, but do not suffice to establish effective acceleration at large scale. Several blue hydrogen projects are in development in the region. The identified national objectives are distinct and confirm neither 19 Mt/year nor a joint status as the world’s leading exporter by 2060. To put this in perspective, global hydrogen demand across all uses was close to 100 million tonnes in 2024 according to the IEA. Supplying a significant share of this market from a single region is a serious industrial proposition, not a pious wish.

Carbon capture figures remain uncertain at large scale

CCUS is the linchpin of the Gulf’s climate argument. Without it, blue hydrogen remains a high-carbon-intensity energy: manufacturing one kilogram of hydrogen from natural gas emits between 8 and 12 kg of CO₂ if nothing is captured. An intensity below 2 kgCO2e/kgH2 requires very high capture performance and low upstream methane emissions; it does not follow automatically from effective capture. The gap is enormous, and the actual performance of facilities determines whether the Gulf’s blue hydrogen will be accepted as “low-carbon” by its future European or Asian customers.

Yet large-scale CCUS projects have a complicated history. Several flagship installations have seen their actual capture rates remain well below initial projections. The Quest project in Alberta, often cited as a benchmark, has captured approximately 1.2 million tonnes of CO₂ per year since 2015, close to its objectives. Similar facilities in other contexts have captured 50 to 70 percent of what they promised. CCUS works in the laboratory; its industrial deployment produces variable results.

The question is whether Gulf projects will achieve announced capture rates at industrial scale.

ADNOC brought into service in 2016 the first large-scale CCUS facility in the Middle East on its steel operations. The record, a decade later, is technically encouraging but modest in volume: approximately 800,000 tonnes of CO₂ captured per year, reinjected into reservoirs to improve oil recovery. This latter use is precisely what some European regulators consider a diversion of the concept: captured CO₂ serves to extract more oil, which calls into question the net balance. It is a real debate, and buyers of blue hydrogen from the Gulf will have to arbitrate it.

Global oil demand: the only parameter that really matters

Oil and gas demand is one factor among several, along with costs, markets, infrastructure, and certification rules.

The STEPS scenario projects a plateau around 102 mb/d toward 2030, followed by a gradual decline. In the STEPS, hydrocarbons remain important but the system becomes more electrified and clean energy, including in particular renewables, nuclear, efficiency, and electrification, covers practically all additional growth in energy demand. But the IEA also publishes a more ambitious scenario (NZE, Net Zero Emissions by 2050), in which demand falls well below 60 million barrels per day by 2035, due to transport electrification and energy efficiency. In this second world, a significant portion of these investments risked becoming stranded assets: infrastructure paid for and unusable before being fully depreciated.

The actual trajectory lies somewhere between these two scenarios. What deserves attention is the speed at which certain signals are accelerating. Global electric vehicle sales represented approximately 20 percent of new registrations in 2024, according to the IEA. In China, the world’s largest car consumer, this figure exceeds 40 percent. Each electric vehicle in circulation avoids part of the consumption that would have been necessary for a comparable combustion vehicle, subject to usage patterns and fleet renewal.

The effect is not notable year by year. Cumulated over ten years, it is.

Technologies for exiting coal invite themselves into the Gulf’s equation: the more alternatives to fossils become competitive, the lower the demand floor on which the investments rest. The profitability of the bet depends on a threshold that no one can yet fix with certainty.

Aramco, ADNOC, and QatarEnergy: three strategies within the same ambition

The three major national companies in the region are not playing exactly the same score, even if their general direction converges.

Saudi Aramco remains the most conservative in its communications. The company maintains a production capacity target of 12 million barrels per day, without a plateau date. Its investments in CCUS and blue hydrogen complement its oil production, but Aramco also presents them as a way to diversify demand and its product portfolio. Aramco bets on its position as the world’s lowest-cost producer: its extraction cost runs around 3 dollars per barrel, against significantly higher costs for American shale producers. In a contracting market, low-cost producers typically have an advantage, without guarantee that the last barrels produced will come exclusively from them.

Aramco intends to be among them.

ADNOC (Abu Dhabi National Oil Company) adopts a more aggressive posture on diversification. The company has announced massive investments in renewables through its subsidiary Masdar, which aims for 100 gigawatts of renewable capacity by 2030. It is simultaneously building blue and green hydrogen capacity, without publicly deciding between the two. Azerbaijan and Egypt are targeted as growth relays, beyond the Gulf’s borders. ADNOC positions itself less as an oil producer that lasts than as an energy company that transforms.

QatarEnergy bets first on liquefied natural gas. Qatar is committing several billion dollars to significantly increase its LNG liquefaction capacity by 2030. QatarEnergy presents natural gas as an essential and sustainable fuel of destination for several decades, where access to electricity remains to be universalized in certain areas. Blue hydrogen comes as a complement: QatarEnergy had signed with Shell an agreement to consider joint investments in blue and green hydrogen in the United Kingdom, and a hydrogen cooperation agreement with H2Korea.

What is decided before 2035: the point of asset irreversibility

The notion of a stranded asset deserves a precise definition, as it is often misused in public debate. A stranded asset is an asset built and technically operational, but which can no longer be monetized because the market it was supposed to serve has disappeared or contracted before the end of its economic life.

In the case of the Gulf, the risk is not symmetrical. If oil demand remains high, current investments could generate satisfactory returns. If it collapses, losses are concentrated in producing countries, whose dependence on oil revenues varies by indicator and by country. Saudi Arabia needs a barrel price around 80 dollars to balance its budget according to IMF estimates. Uninvestigated capital investments could worsen budgetary tensions.

This asymmetric risk explains why the signals to watch in coming years are not announcements by oil companies, but demand indicators. The penetration rate of electric vehicles in India, the world’s third-largest oil consumer after the United States and China, is a first-order signal. The speed at which Asian economies electrify their heavy industries is another. And more structurally, the trajectory of productivity gains linked to automation in industrial economies will determine their future energy intensity.

The window from 2026 to 2035 is therefore a critical period. Committed investments have multi-decade depreciation periods. A CCUS project decided in 2026 depends on long-term revenue and usage prospects, whose horizon varies by contract, asset, and public framework. The decisions being made now in the Gulf’s energy ministries, as well as the application of European rules on the method of evaluating low-carbon hydrogen, will influence the viability of this bet.

The European hydrogen market, unexpected arbiter of the Gulf’s bet

Europe is at the center of the equation, and not just as a potential customer. It also sets the rules of the game.

The EU has already adopted criteria for renewable hydrogen; the specific modalities for low-carbon hydrogen followed a distinct regulatory process. For blue hydrogen, certification depends on the capture rate actually achieved and the full lifecycle of emissions, from wellhead to delivery point. The European methodological criteria applicable to low-carbon hydrogen were adopted in 2025, and these criteria condition regulatory qualification and certification, whose structure influences commercial access and profitability.

A blue hydrogen project that does not meet the applicable European threshold must reduce its lifecycle emission intensity, for example through more capture with permanent storage not associated with EOR and fewer methane leaks, or not be eligible. Green hydrogen constitutes an alternative option among others.

The Gulf has comparative advantages for green hydrogen production: exceptional sunshine, vast available space, and solar electricity costs among the lowest in the world. ADNOC and its partners are aware of this, which explains Masdar’s investments. The relative costs of green and blue hydrogen vary greatly depending on local conditions and energy prices.

The timeline plays a role here. If electrolyzer costs continue to fall at the pace of recent years, green hydrogen could become competitive with blue hydrogen by 2030-2035. In that case, Gulf producers risk seeing the economic viability of their blue hydrogen investments diminish in the face of an alternative less carbon-intensive and less dependent on hydrocarbons.

Asia, less stringent on carbon criteria in the short term, offers a substitute market. Japan and South Korea have both signed framework agreements with Gulf producers for blue hydrogen deliveries. But their own climate commitments for 2050 could tighten import criteria in the second half of the 2030s. The window of opportunity for blue hydrogen is real. It is probably not several decades long.

The 110 billion and the geopolitics of transition

Beyond financial profitability, the Gulf’s strategy has a geopolitical dimension that must be named.

Gulf Cooperation Council (GCC) countries have understood that their influence in the global energy system depends on their ability to remain indispensable suppliers, regardless of the form energy takes tomorrow. Selling oil, then gas, then hydrogen, then potentially ammonia or transported electricity: the logic is one of continuous repositioning, not an exit from fossils. It is a strategy of geopolitical survival as much as an industrial strategy.

This reading illuminates why Gulf companies invest in technologies whose long-term profitability is uncertain. The alternative, doing nothing and letting demand collapse without having developed new offerings, is perceived as even more risky. These investments are not solely a bet on the hydrogen market. They also buy time and legitimacy in international climate forums, where producing countries can now present themselves as actors of transition rather than mere brakes.

This posture has a clear limit: it works as long as the international community accepts that decarbonizing hydrocarbon production is a valid contribution to transition. Criteria excluding these projects could reduce their access to certain sustainable financing, without demonstrating the drying up of all international financing.

The question that will remain open until at least 2030: will a global market for low-carbon hydrogen produced from natural gas emerge at a significant size to justify the simultaneous projects in development in the region? The answers will depend notably on European decisions on certification criteria, the evolution of green hydrogen costs, and the extent of electrification of Asian economies. None of these variables is fixed.

Sources

  1. DNV Energy Transition Outlook 2026 – GCC report
  2. IEA – World Energy Outlook 2024 (oil demand data, STEPS and NZE scenarios)
  3. IEA – Global Hydrogen Review 2024 (global hydrogen demand)
  4. IEA – Oil and Gas Decarbonization Outlook
  5. Wood Mackenzie – Energy mix analysis (GCC blue hydrogen projects)
  6. IMF – Article IV Consultation Saudi Arabia (budget equilibrium price)
  7. Research and Markets – CCUS Middle East market analysis
  8. OilPrice.com – GCC energy investment tracker 2026