Upstream Is Falling Behind on Future Oil Supply

Anyone following upstream oil and gas news over the past year will notice a recurring theme. Global oil demand isn’t collapsing, yet upstream supply capacity is becoming increasingly fragile. 

Even as the energy transition accelerates in some regions, most of the world still relies on oil for heavy industry, petrochemicals, aviation, and transport. But the supply side, which is already stretched by years of underinvestment is struggling to keep pace.

Capital budgets are tightening. Geopolitics remain unpredictable. Exploration success has slowed. And many independents are consolidating instead of sanctioning new long-cycle projects. Meanwhile, natural decline continues carving out millions of barrels per day from existing fields.

The Industry Mood: Demand Isn’t Going Anywhere

Executives across international oil companies (IOCs), national oil companies (NOCs), and major independents share a consistent message: “Peak demand is further out than the headlines suggest.”

Despite electric vehicles (EVs) increasing their market share and policy signals shifting toward decarbonization, global liquids demand has held strong.

Why Demand Remains Resilient

Three forces are shaping consumption patterns:

1. Slow Progress in Heavy-Transport Alternatives

No scalable low-carbon substitutes yet exist for long-haul aviation, maritime shipping, petrochemical feedstocks, or heavy-duty trucking. Even strong EV adoption does little to reduce demand for diesel, jet fuel, and naphtha.

2. Energy Security Takes Priority

Post-2022, governments are more concerned with reliable energy than fast decarbonization. Countries across Asia, Africa, and Eastern Europe continue to procure oil aggressively to avoid future disruptions.

3. Developing Economies Are Driving Growth

Asia—not the U.S. or Europe—is setting the marginal demand curve. Population growth, rising incomes, and industrial expansion support ongoing consumption.

Demand Outlook Through 2040

Across most major outlooks, global oil demand sits at roughly 104 million barrels per day today and is expected to rise toward 108 million barrels per day by the early 2030s before leveling off at high levels rather than falling sharply. 

In a slower-transition scenario, demand could climb even higher, reaching 110-113 million barrels per day and remaining elevated well into the late 2030s. This matters because even a flat demand curve at such high volumes requires enormous new supply; natural field declines never pause, meaning the industry must continue replacing millions of barrels per day just to maintain balance.

A Shrinking Investor Pool and Tighter Capital Markets

A growing share of today’s upstream oil and gas news highlights that upstream consolidation is accelerating, especially among North American independents and select global E&Ps. But consolidation has deep consequences for future supply, because fewer companies means fewer decision-makers with the appetite (and balance-sheet capacity) to greenlight large, long-cycle projects.

1. Fewer Companies = Fewer Project Sanctions 

The wave of mergers among U.S. independents has dramatically reduced the pool of mid-cap operators capable of sanctioning new developments. This matters because mid-caps historically approved many high-quality offshore and onshore projects that fell outside the scope of supermajors and NOCs. 

Larger companies, by design, now lean toward lower-risk opportunities such as brownfield expansions, tiebacks, and short-cycle shale drilling. These projects offer faster payback periods and predictable decline profiles, but they do not meaningfully expand long-term global supply. As a result, greenfield offshore megaprojects are advancing only when prices remain both high and stable, a condition the current market struggles to deliver.

2. Investors Want Higher Returns, Not Higher Output 

The investor base that once rewarded aggressive production growth no longer exists. Since the post-2014 downturn, capital markets have shifted sharply toward cash generation and balance-sheet strength. Today’s shareholders consistently prioritize dividends, share buybacks, debt reduction, and rigorous capital discipline over volumetric expansion. That preference constrains upstream spending, especially in regions where breakevens are uncertain or where the payback period extends beyond typical market cycles.

3. ESG Financing Constraints Still Matter 

Although some ESG restrictions have softened, financing channels for high-intensity or high-risk upstream projects remain constrained. Arctic developments, oil sands expansions, and deep frontier drilling continue to face reduced access to Western capital and stricter lending criteria. Banks and institutional investors remain cautious about reputational exposure, long-cycle carbon intensity, and regulatory uncertainty. Consequently, capital availability is improving unevenly, flowing more readily toward low-emission barrels, NOC partnerships, and brownfield growth rather than frontier exploration.

4. A Strategic Shift Toward NOCs 

With IOCs becoming more selective, national oil companies have effectively become the long-term anchors of global supply. But even NOCs carry significant constraints of their own: government-mandated budget ceilings, competing domestic spending priorities, geopolitical sanctions (especially affecting Russia), and currency instability in producers such as Nigeria, Egypt, and Angola. These pressures limit their ability to deliver the scale of new supply needed to close the widening gap between demand and natural decline.

A Global Sanctioning Deficit Taken together, these trends point to a structural issue: sanctioned project volumes continue to fall far short of what long-term demand requires. Even as the world debates the pace of energy transition, the underlying math of supply replacement suggests that future barrels are not being approved at a pace sufficient to meet the 2030s’ needs.

Technology and AI: Transformative Potential, Incremental Reality

A steady stream of upstream oil and gas news highlights breakthroughs in AI, automation, and the digital transformation of exploration and production. Yes, the digital transformation of exploration and production is real, and in some areas, the gains are substantial. But these gains are incremental, not transformative enough to offset structural underinvestment or create millions of barrels per day of new supply.

Documented Performance Improvements

Across the industry, operators continue to report measurable benefits from digital tools and advanced analytics:

• 20–50% reductions in seismic processing times, driven by cloud computing and AI-assisted interpretation.

• Higher exploration success rates from pattern-recognition algorithms trained on decades of seismic datasets.

• Improved drilling efficiency, including fewer non-productive time (NPT) events and more consistent drilling curves, thanks to predictive maintenance and automated well planning.

• More accurate reservoir simulation models, where machine learning smooths the integration of geological, geophysical, and production data.

These improvements matter. They make wells cheaper, shorten project cycles, and expand what’s economically viable. 

Volatility Is Undermining 2025 Spending Plans

At the beginning of 2025, most forecasts pointed toward a steady year for upstream investment. Analysts expected global upstream capex to rise by 5–7%, supported by stable demand growth and disciplined shale spending. Many operators entered the year with strong balance sheets and a willingness to gradually expand drilling and project sanctioning.

Then the price structure broke.

By Q2, Brent slid from the $80–85/bbl range to the low $60s, wiping out the fragile confidence that underpinned early-year budgets. Rystad’s 2025 Upstream Investment Review notes that operators begin tightening capital as soon as Brent falls below $70/bbl, a level where discretionary drilling becomes harder to justify.

Volatility is strangling the very optimism that underpinned 2025 sending plans. While upstream investment is still expected to grow marginally, the revised outlook is far more cautious. Only projects with robust economics, rapid payback periods, and strong strategic alignment are moving forward. 

Conclusion

The global upstream sector is entering a period defined by contradictions. On one hand, demand remains resilient and likely to plateau at high levels for decades. On the other, supply capacity is weakening, constrained by capital discipline, a shrinking investable company pool, and natural declines outpacing new project sanctioning.

Technology will help improve efficiency, but cannot replace the structural need for long-term upstream investment. Governments are adjusting, NOCs are taking the lead, and the majors remain cautious but active, yet the numbers show a clear gap emerging.

Without a meaningful rise in upstream investment, the world risks entering the 2030s with insufficient supply, tighter balances, and heightened price volatility. The message across all upstream oil and gas news sources is consistent: If we want stable energy markets in the future, investment must accelerate now.

FAQs

1. Why is oil demand expected to remain resilient?

Demand remains steady due to limited alternatives in heavy transport and petrochemicals, growing energy needs in developing economies, and policymakers’ focus on energy affordability and security. Even with efficiency gains, these factors support a long plateau in consumption.

2. What is causing the future supply gap?

Natural field declines are removing millions of barrels per day each year. To offset this and meet modest demand growth, the industry needs over 20 million b/d of new supply by 2035, far more than current project pipelines can deliver.

3. How are governments encouraging upstream investment?

Countries like Nigeria and India are revising fiscal terms, simplifying regulations, and opening new acreage to attract IOCs and major independents. These measures aim to increase exploration and speed up development.

4. Is AI a major solution for boosting supply?

AI is improving subsurface interpretation, drilling efficiency, and reservoir modeling, but it is not yet transforming overall supply levels. Most benefits today relate to cost and cycle-time improvements.

5. What happens if investment stays low through 2026?

A prolonged investment slowdown could lead to tighter markets later in the decade, reduced non-OPEC supply growth, and increased reliance on OPEC+. This environment raises the risk of future price spikes and supply shortages.