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Four Oil and Gas Trends for 2026 in EMIA
Making predictions in oil and gas is a risky sport. Ever since David White, chief geologist at the United States Geological Survey, said peak oil would arrive by 1920, the industry has made a habit of proving forecasts wrong.
The challenge is even greater at the end of a year 2025 when the two superpowers have made unpredictability a part of their strategy. The economic impact of tariffs and the reality of the EU’s pledge to buy $250bn of US oil and gas every year remain to be fully seen. Meanwhile, China’s strategy of stockpiling oil has confounded experts. The long-tail effects of Western sanctions on Russia are also still unfolding: Russia’s cheap crude oil has helped India’s refining sector build a competitive edge but it has also become a flashpoint in US-India trade tensions, with effects that will be seen in 2026.
The long-tail effects of Western sanctions on Russia are also still unfolding: For example, Russia’s cheap crude oil has helped India’s refining sector build a competitive edge but it has also become a flashpoint in US-India trade tensions, with effects that will be seen in 2026.
The challenge is even greater at the end of a year 2025 when the two superpowers have made unpredictability a part of their strategy. The economic impact of tariffs and the reality of the EU’s pledge to buy $250bn of US oil and gas every year remain to be fully seen. Meanwhile, China’s strategy of stockpiling oil has confounded experts. The long-tail effects of Western sanctions on Russia are also still unfolding: Russia’s cheap crude oil has helped India’s refining sector build a competitive edge but it has also become a flashpoint in US-India trade tensions, with effects that will be seen in 2026.
The long-tail effects of Western sanctions on Russia are also still unfolding: For example, Russia’s cheap crude oil has helped India’s refining sector build a competitive edge but it has also become a flashpoint in US-India trade tensions, with effects that will be seen in 2026.
Still, there are markers to work with. The year ends with a widely held view that crude could dip below $60 a barrel, given high inventories and subdued global growth. At the same time, 2025 may be remembered as the first “post-phaseout” year: The once-firm consensus that oil and gas were in decline has softened and several voices now suggest global demand could expand for another two decades.
The four trends that follow reflect this mixed signals. They also point to the need for companies to build and operate at lower cost, strengthen their license to operate and prepare for a future where adaptability counts as much as volume.
1. Capital discipline is the watchword
Let’s start with one certain thing for 2026: Capital spending is tightening, and it will shape every upstream decision. Wood Mackenzie expects global oil and gas production capex to fall 4.3% to $341.9 billion, the first annual decline since 2020.
In EMIA, investment splits along cost lines. Middle Eastern national oil companies are pressing advantages in low‑cost basins. Aramco is moving forward with $52-$58bn capex investments for 2025, upstream capex rose 19% in 2024 to about $39 billion, and ADNOC is advancing a multi‑year plan to reach 5 mb/d of oil capacity by 2027. These are long‑cycle, low‑breakeven developments that still clear the bar. Europe, by contrast, is moving into harvest mode. The North Sea lacks a robust slate of new project sanctions to offset declines and UK production is trending toward a multi‑decade low by 2030, while Norway’s recent wave of projects stabilizes output only for a time before declines resume without more approvals.
Across the board, 2026 will be a year when capital discipline, not volume growth, is the organizing principle for EMIA upstream. Large companies will opt for smaller bets, with brownfield tie‑backs and phased expansions accounting for a larger share of final investment decisions, and a greater focus on risk-adjusted cash returns and delivery certainty.
This focus will have implications on frontier oil projects: Guyana should remain attractive with low breakevens, while Namibia’s discoveries will need phased development to control costs and prove reliability. In a country like India that presents regulatory challenges, the push to exploit oil fields will advance through incremental projects and joint ventures rather than large bets.
The emphasis on capital discipline will also be reflected in tools and methods to strengthen project control and risk management. Approaches like Enterprise Project Performance (EPP) platforms, which unify scope, cost and schedule so leaders see risk exposure early, should gain traction. The use of AI for project controls should also develop as companies try to reduce the chance of being caught mid‑build if market conditions shift.
2. To Reduce O&M Costs, Companies bet on AI and APM
Cost pressures are not only visible in projects but also in operations. As some companies have started slashing jobs, Chevron chief executive Mike Wirth rightly pointed out that “The way we protect the most jobs for the most people is by remaining competitive.”
The larger prize sits in the asset base. APM paired with a plant‑level digital twin turns condition data into maintenance decisions that cut wasted labor, parts and energy. In a recently published paper, British and Australian researchers have found that this duo can reduce O&M costs by up to 20%, which is the difference between running a mature asset for cash and closing it. The fastest wins lie in high‑consequence equipment, such as compressor trains, gas turbines, fired heaters, Fluid catalytic cracking and hydrocracker circuits, sour‑gas handling or produced‑water systems. Predicting failures sooner can save money while trimming Scope 1 and 2 emissions at the same time.
Companies will also increasingly bet on AI, not just for back-office tasks but for the management of critical assets. As of 2024, the industry starts from a relatively far position, with only one in four employees saying their company uses AI . At the time, the single most cited use case was automating workflow and collaboration (30%), followed by using data analytics to optimize production (28%) and performing remote monitoring.
3. With Methane Reduction and Carbon Capture, decarbonization moves closer to the operating model
Another domain that could move closer to the core of operations is emissions cuts. 2025 marked the year the industry broadly moved away from side ventures in renewable energy, particularly if they showed little profitability or alignment with their core business model.
2026 should favor two strategies with strong potential in reducing emissions while making a profit: methane abatement and carbon capture, utilization and storage.
The IEA’s Global Methane Tracker 2025 puts energy‑sector methane above 120 Mt per year and shows that about 70% could be avoided with existing technologies, with many measures paying back within a year because captured gas is saleable. Add to that 100 bcm of gas that could have reached market in 2024 with proper methane abatement, and 150 bcm still flared globally each year.
2026 could be the year EMIA operators treat methane and flaring as production losses, not PR issues. Expect to see company‑level methane intensity curves fall and routine flaring programs retired on specific assets. Satellite‑verified super‑emitters will get closed out faster, with continuous monitoring on high‑risk sites. Only 5% of global oil and gas output meets near‑zero methane standards today; that share should rise.
In parallel, Carbon Capture, Utilization and Storage (CCUS) is maturing from pilots to plant‑scale retrofits. The operational focus has moved to capture units bolted onto hydrogen, FCC and reformer streams in refineries and petrochemical complexes. Rising carbon costs in Europe (around the €70/t range over the past year) sharpen the math. Here is the useful nuance for 2026: operators will prioritize low‑cost methane and flare cuts first, then add CCUS where process streams are concentrated and uptime is high.
Emissions management gets folded into everyday tools. Enterprise Asset Management (EAM) now carries emissions KPIs alongside reliability. Digital twins of plants simulate capture loads, pressure drops and steam balances next to throughput optimization. AI speeds leak detection by fusing fixed sensors, drones and satellites. In short, decarbonization is becoming an operations problem with operations tools.
4. European refining shrinks, then smartens
Due to the Atlantic Basin's structural decline, refining in Europe is facing a crisis marked by declining profitability and increased reliance on imports from other regions. That trend should accelerate refinery closures through 2026, and several sites convert units to biofuels or sustainable aviation fuels (SAF) co‑processing rather than keep crude runs. Shell closed Wesseling in Germany, Petroineos shut Grangemouth and more sites are under review. Industry studies suggest Europe could see up to 2.1 mb/d of CDU capacity removed by 2030 if margins and policy headwinds persist.
Europe enters 2027 with less crude capacity, higher average utilization and more integrated low‑carbon units than in 2024. Value will come from energy efficiency, reliability and unit flexibility, not just barrel throughput.
The reliability prize is big. Unplanned downtime in an average mid‑sized refinery destroys tens of millions of dollars a year. Plants are using APM in EAM, advanced process control and predictive analytics to stabilize heat‑intensive units and hydrogen systems. Several European sites have run digital turnarounds and are building site‑wide digital twins for change management and permit‑to‑work visibility. Cross‑industry examples, like district‑heat integration and “paperless” operating models, show how refineries can harden social license while cutting fuel use.
These investments address a simple predicament: 2026 should mark the end of a cycle for oil and gas firms. Such years are marked by stronger pressures on margins, costs and capital expenditures. Once again, some will call this a sunset era for oil and gas. However, these calls have been made many times since 1920 and have always been proven wrong. What has stood true is that, in the boom-and-bust cycles the industry is accustomed to, the "bust" part is where a firm’s competitive advantage can be built - and where firms that navigate the downturn well can pull ahead.
The four trends that follow reflect this mixed signals. They also point to the need for companies to build and operate at lower cost, strengthen their license to operate and prepare for a future where adaptability counts as much as volume.
1. Capital discipline is the watchword
Let’s start with one certain thing for 2026: Capital spending is tightening, and it will shape every upstream decision. Wood Mackenzie expects global oil and gas production capex to fall 4.3% to $341.9 billion, the first annual decline since 2020.
In EMIA, investment splits along cost lines. Middle Eastern national oil companies are pressing advantages in low‑cost basins. Aramco is moving forward with $52-$58bn capex investments for 2025, upstream capex rose 19% in 2024 to about $39 billion, and ADNOC is advancing a multi‑year plan to reach 5 mb/d of oil capacity by 2027. These are long‑cycle, low‑breakeven developments that still clear the bar. Europe, by contrast, is moving into harvest mode. The North Sea lacks a robust slate of new project sanctions to offset declines and UK production is trending toward a multi‑decade low by 2030, while Norway’s recent wave of projects stabilizes output only for a time before declines resume without more approvals.
Across the board, 2026 will be a year when capital discipline, not volume growth, is the organizing principle for EMIA upstream. Large companies will opt for smaller bets, with brownfield tie‑backs and phased expansions accounting for a larger share of final investment decisions, and a greater focus on risk-adjusted cash returns and delivery certainty.
This focus will have implications on frontier oil projects: Guyana should remain attractive with low breakevens, while Namibia’s discoveries will need phased development to control costs and prove reliability. In a country like India that presents regulatory challenges, the push to exploit oil fields will advance through incremental projects and joint ventures rather than large bets.
The emphasis on capital discipline will also be reflected in tools and methods to strengthen project control and risk management. Approaches like Enterprise Project Performance (EPP) platforms, which unify scope, cost and schedule so leaders see risk exposure early, should gain traction. The use of AI for project controls should also develop as companies try to reduce the chance of being caught mid‑build if market conditions shift.
2. To Reduce O&M Costs, Companies bet on AI and APM
Cost pressures are not only visible in projects but also in operations. As some companies have started slashing jobs, Chevron chief executive Mike Wirth rightly pointed out that “The way we protect the most jobs for the most people is by remaining competitive.”
The larger prize sits in the asset base. APM paired with a plant‑level digital twin turns condition data into maintenance decisions that cut wasted labor, parts and energy. In a recently published paper, British and Australian researchers have found that this duo can reduce O&M costs by up to 20%, which is the difference between running a mature asset for cash and closing it. The fastest wins lie in high‑consequence equipment, such as compressor trains, gas turbines, fired heaters, Fluid catalytic cracking and hydrocracker circuits, sour‑gas handling or produced‑water systems. Predicting failures sooner can save money while trimming Scope 1 and 2 emissions at the same time.
Companies will also increasingly bet on AI, not just for back-office tasks but for the management of critical assets. As of 2024, the industry starts from a relatively far position, with only one in four employees saying their company uses AI . At the time, the single most cited use case was automating workflow and collaboration (30%), followed by using data analytics to optimize production (28%) and performing remote monitoring.
3. With Methane Reduction and Carbon Capture, decarbonization moves closer to the operating model
Another domain that could move closer to the core of operations is emissions cuts. 2025 marked the year the industry broadly moved away from side ventures in renewable energy, particularly if they showed little profitability or alignment with their core business model.
2026 should favor two strategies with strong potential in reducing emissions while making a profit: methane abatement and carbon capture, utilization and storage.
The IEA’s Global Methane Tracker 2025 puts energy‑sector methane above 120 Mt per year and shows that about 70% could be avoided with existing technologies, with many measures paying back within a year because captured gas is saleable. Add to that 100 bcm of gas that could have reached market in 2024 with proper methane abatement, and 150 bcm still flared globally each year.
2026 could be the year EMIA operators treat methane and flaring as production losses, not PR issues. Expect to see company‑level methane intensity curves fall and routine flaring programs retired on specific assets. Satellite‑verified super‑emitters will get closed out faster, with continuous monitoring on high‑risk sites. Only 5% of global oil and gas output meets near‑zero methane standards today; that share should rise.
In parallel, Carbon Capture, Utilization and Storage (CCUS) is maturing from pilots to plant‑scale retrofits. The operational focus has moved to capture units bolted onto hydrogen, FCC and reformer streams in refineries and petrochemical complexes. Rising carbon costs in Europe (around the €70/t range over the past year) sharpen the math. Here is the useful nuance for 2026: operators will prioritize low‑cost methane and flare cuts first, then add CCUS where process streams are concentrated and uptime is high.
Emissions management gets folded into everyday tools. Enterprise Asset Management (EAM) now carries emissions KPIs alongside reliability. Digital twins of plants simulate capture loads, pressure drops and steam balances next to throughput optimization. AI speeds leak detection by fusing fixed sensors, drones and satellites. In short, decarbonization is becoming an operations problem with operations tools.
4. European refining shrinks, then smartens
Due to the Atlantic Basin's structural decline, refining in Europe is facing a crisis marked by declining profitability and increased reliance on imports from other regions. That trend should accelerate refinery closures through 2026, and several sites convert units to biofuels or sustainable aviation fuels (SAF) co‑processing rather than keep crude runs. Shell closed Wesseling in Germany, Petroineos shut Grangemouth and more sites are under review. Industry studies suggest Europe could see up to 2.1 mb/d of CDU capacity removed by 2030 if margins and policy headwinds persist.
Europe enters 2027 with less crude capacity, higher average utilization and more integrated low‑carbon units than in 2024. Value will come from energy efficiency, reliability and unit flexibility, not just barrel throughput.
The reliability prize is big. Unplanned downtime in an average mid‑sized refinery destroys tens of millions of dollars a year. Plants are using APM in EAM, advanced process control and predictive analytics to stabilize heat‑intensive units and hydrogen systems. Several European sites have run digital turnarounds and are building site‑wide digital twins for change management and permit‑to‑work visibility. Cross‑industry examples, like district‑heat integration and “paperless” operating models, show how refineries can harden social license while cutting fuel use.
These investments address a simple predicament: 2026 should mark the end of a cycle for oil and gas firms. Such years are marked by stronger pressures on margins, costs and capital expenditures. Once again, some will call this a sunset era for oil and gas. However, these calls have been made many times since 1920 and have always been proven wrong. What has stood true is that, in the boom-and-bust cycles the industry is accustomed to, the "bust" part is where a firm’s competitive advantage can be built - and where firms that navigate the downturn well can pull ahead.