Exploration made the oil majors. But who still knows how to do it?

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Majors and exploration

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Exploration used to be one of the reasons an oil major deserved to be called a major. It found the product the company sold, renewed the resource base and created the projects that would support production for decades. This was not simply a commercial preference. It was a consequence of history.

The predecessor companies of today's majors once controlled extraordinary concessions over some of the largest and cheapest oil resources in the world. Nationalisation progressively removed that privilege. Mexico moved first. Iran, Iraq and Venezuela followed. Across the Middle East, producer states increased their ownership and control, while national oil companies became more powerful. The majors could remain refiners, traders and marketers, but they could not remain major producers by relying on reserves they no longer controlled. If they wanted to survive in their existing form, they had to find large resources elsewhere.

OPEC and the producer states then changed the economics. The embargo and production cuts of 1973 drove prices sharply higher. For the majors, the higher price did not create the need for new resources. The loss of the old concessions had already done that. What it did was make technologically difficult offshore basins economic and worth the risk. It also generated the cash required to develop them.

Necessity drove the majors offshore. The geology was less understood and the engineering more difficult, but crucially, access was available. They built offshore organisations, improved seismic interpretation, learned to install large platforms and pipelines, and committed amounts of capital that few other companies could carry. The majors did not go offshore because it was fashionable. They went because many of the easier doors had closed. The risk was immense, but successful exploration offered a route back to resource scale and strategic control.

BP's giant Forties field provides the perfect example. Forties was discovered in 1970, while the loss of BP's old concessions was forcing the company to search for resources elsewhere. Without that strategic necessity, BP might never have committed the same effort to exploring the North Sea. The 1973 price shock came after the discovery, but it transformed the economics of development.

Forties contained billions of barrels of recoverable oil and required four enormous fixed steel platforms, a major offshore pipeline and an organisation capable of operating in severe North Sea conditions. The commitment was enormous. The risk was repaid many times over.

Forties belonged to the first great offshore era. Floating production, subsea systems, dynamic positioning and better seismic imaging later carried the industry into deep water. Through the 1970s, 1980s and 1990s the majors repeatedly extended the limits of what could be developed, overcoming difficult geology and engineering because success created enormous value.

Exploration in hostile frontier locations was part of what made working in an oil major so exciting and incredibly rewarding.

Exploration was therefore never just another department or budget. It represented a strategic corporate capability. It required skill, knowledge, experienced multidisciplinary teams, commitment from the board and CEO, development expertise and the financial strength to sustain a portfolio through some of the most daunting challenges any corporation is likely to face.

The model survived the price collapse of the 1980s and the low price environment of the 1990s. Consolidation created the modern supermajors, with the scale and balance sheets to manage larger and more technically difficult portfolios. Then the oil price reached its low in 1999 and began a long rise. China became a much larger consumer, spare capacity tightened and concerns about resource scarcity returned. Prices did not rise continuously, but they rose for long enough to change expectations, behaviour and corporate memory.

People who remembered the tough years, the failed projects and prolonged low prices became fewer and less influential. Careers were built by backing the machine, securing projects and delivering growth. An investment case that looked aggressive could appear cautious two years later because the assumed oil price had risen again. Saying yes was repeatedly rewarded. Saying no was a career route to nowhere.

The majors approved ever larger deep water, liquefied natural gas, oil sands, heavy oil and Arctic developments. Many contained enormous resources, but they required long schedules and huge capital commitments before final cost or operating performance could be known. The rising price concealed a worsening problem. Project economics appeared intact because the commodity price was rescuing returns that execution had already damaged.

By late 2013 and early 2014, before the oil price collapsed, almost two thirds of a large sample of major oil and gas projects were over budget and nearly three quarters were late. Returns on capital were falling while spending continued to rise. The industry did not enter the price crash in rude health. It entered with an execution problem that the oil price had been hiding.

The project system had become too large and too hot. Final investment decisions were made using estimates that could be years out of date by the time construction reached its most intensive phase. The assumptions approved by a board no longer described the market in which the project was being built.

Experienced project managers, engineers and supervisors became scarce. The best yards were full. Strong contractors were stretched and work moved to weaker suppliers. Interfaces multiplied, productivity deteriorated and delay created more delay as equipment, vessels and people had to be rescheduled. Many inside the companies knew what was happening, but momentum was difficult to resist. Senior careers had been built by supporting growth, governments expected investment, partners wanted sanction and boards feared missing the next large resource. Intended returns were being destroyed before the oil price fell.

The 2014 crash did not create the project crisis. It revealed it. Weaker demand, rapid growth in United States production and OPEC's decision to maintain output cut the price in half. Projects that had struggled above $100 a barrel suddenly looked indefensible. The response was necessary. Portfolios were simplified, lower break even prices were demanded and management teams rediscovered capital discipline. Exploration was an obvious place to cut because it could be deferred without immediately reducing current production.

Shale changed the comparison as well. Capital could be committed a well at a time, production arrived quickly and drilling could be slowed within months. A large offshore project required confidence in prices, costs and demand many years into the future. Shale offered flexibility that a conventional megaproject could not. For the North American majors in particular, it became a convenient escape route from the cost and uncertainty of conventional exploration.

Some of the decline in reported exploration spending reflected lower rig and service costs, but the retreat was real. Global exploration investment had begun falling before 2014 and then fell by almost half over the following four years. Teams were reduced, offices closed and basin knowledge dispersed.

The savings appeared quickly. The strategic cost did not. A discovery missing from the portfolio today might trace back to acreage that was not acquired, a prospect that was not matured or a technical team that was broken up a decade ago. Exploration is easy to cut precisely because the damage takes so long to become visible.

Covid delivered another severe shock in 2020. Demand collapsed, capital was cut again and exploration programmes were deferred. At the same time, enthusiasm for the energy transition changed what investors and boards believed an oil company should become. Long duration oil projects were viewed with suspicion. Companies were pushed towards shorter cycle opportunities, faster payback, lower operating emissions and resources close to existing infrastructure. Much of this was sensible. The industry had earned the pressure through poor execution and weak returns.

The mistake was believing exploration capability could be reduced without creating a future cost. Acreage, country relationships, basin knowledge and drillable prospects take years to assemble. They cannot be recreated by changing a strategy presentation when the market moves again. BP and Shell went furthest among the European majors in narrowing the future role of hydrocarbons. BP planned for sharply lower oil and gas production and said it would not explore in new countries. Shell said its oil production had peaked and planned no new frontier entries after 2025.

Eni and TotalEnergies built transition businesses but continued to treat hydrocarbons as central to growth and cash generation. ExxonMobil and Chevron never made equivalent commitments to shrink. The Europeans made the larger transition strategy mistakes. The Americans avoided those mistakes, but became more dependent on shale and acquisitions to repair organic resource renewal they had neglected. Neither approach removed the need to find large conventional resources, and the weakness is becoming increasingly visible.

Exploration did not stop. It became narrower and was asked to do something different. The old model sought new provinces and decades of resource depth. The new model preferred discoveries near existing facilities, projects that could be phased, gas connected to established markets and fewer large frontier bets.

The number of companies drilling high impact wells roughly halved when the five years from 2010 to 2014 are compared with the five years from 2020 to 2024. Only 64 such wells were completed in 2025. The industry had not lost the technical ability to explore, but far fewer companies were willing to sustain it.

ExxonMobil is the obvious place to start because Liza is the outstanding exploration success of the period. Exxon entered Guyana in 2008 and drilled the discovery in 2015 after decades of unsuccessful or noncommercial wells across the wider basin. Liza proved a working petroleum system at commercial scale and changed the understanding of an entire region.

Stabroek now contains nearly 11 billion boe and more than 30 discoveries. First oil arrived less than five years after Liza, an exceptional performance in a new offshore province. ExxonMobil did not simply make a great discovery. It converted it with the speed and conviction expected of a major.

The easy version of the story gives equal credit to every discovery that followed. That is wrong. Liza was the frontier breakthrough. Once it and the appraisal wells had proved source, charge, reservoir and scale, the prospects around it were materially less risky. The thirtieth discovery was not the same achievement as the first. One well changed the risk on everything around it.

ExxonMobil benefited enormously from Guyana and then had the luxury of broadening the type of resources it owned. It bought Pioneer and added a vast Permian inventory. Those were purchased barrels, but they sit alongside a genuine organic triumph.

The combination of Stabroek and the Permian creates concentration risk, however. Shale requires continuous drilling to offset rapid decline and has received repeated reprieves from technological improvement. Those gains will become harder to repeat. Guyana is now central to Exxon's production growth and valuation, so political, fiscal or operating disruption would be felt quickly in the shares. Exxon has the best single exploration result of the period, but it still needs to find what comes after Liza, or the Permian for that matter.

Eni is the strongest exploration company in the group because its success is more repeatable. It continued entering acreage and drilling while connecting exploration closely to appraisal, development and capital recycling. It often takes operatorship and a high working interest, proves the resource, moves quickly and then sells part while retaining control.

Zohr in Egypt showed the strength and limitations of the model. The giant gas field was discovered in 2015, sanctioned within months and producing in less than two and a half years. That speed was extraordinary. Later reserve assessments were materially lower than early expectations and production declined after water breakthrough. Zohr remains a major achievement, but not the unqualified success it first appeared.

Baleine in Cote d'Ivoire moved from discovery to production in less than two years. Eni also suffered a poor drilling year in 2024. The longer record is more persuasive, with a system that has continued to create opportunities and convert them into durable value.

Eni bought Neptune, so this is not a romantic story of purely organic growth. The acquisition supplemented an exploration engine that remained alive. On repeatability, cost and development speed, Eni has the most convincing all round model. I admit to being an admirer of the company, but the evidence supports the conclusion.

TotalEnergies has been more selective. Its recent exploration spending and completed well count have fallen, but it retained a strong reserve position and the ability to participate in material new provinces.

Namibia had already tested the patience of explorers for more than half a century. The first offshore wells were drilled in the 1960s and Kudu gas was discovered in 1974, but the field never entered production and decades of subsequent drilling failed to produce a commercial breakthrough. In 2022 Shell's Graff discovery and TotalEnergies' Venus discovery finally changed the understanding of the Orange Basin.

Venus has progressed through appraisal towards a potential development decision. In Suriname, Sapakara and Krabdagu underpin GranMorgu, a major project that has already been sanctioned. These are serious resources moving towards serious developments. TotalEnergies is making fewer bets, but some have created material options. Its reserve life remains above 12 years, far stronger than BP or Shell, although recent reserve additions also reflect revisions and project maturation.

Selectivity can work when the existing portfolio is deep and discoveries convert. The danger is timing. A smaller exploration portfolio looks efficient while large projects are moving towards production. The weakness only appears when the next generation is not ready. Today's abundance almost always reflects decisions made years earlier.

Now, before we continue, regular readers may think I am ganging up on BP. Perhaps I am, but it remains an easy target because its strategy and leadership repeatedly disappoint. That is particularly frustrating because the underlying company is so much better than its recent direction.

BP is the clearest example of strategic discontinuity. It did not stop exploring completely, and its technical teams continued working prospects and drilling wells. The strategic direction nevertheless changed, and it changed at the wrong part of the resource cycle.

BP's caution cannot be separated from Macondo. The company had experienced the catastrophic cost of operating and governance failure. Greater discipline was essential. But caution became something broader. In 2020 BP planned for oil and gas production to be around 40 percent lower by 2030 and said it would not explore in new countries. This was a choice by leadership, not a limitation of capability.

That was not simply a decision about one year's spending. Country access, basin knowledge and a portfolio of prospects take years to build. When a company stops feeding the front of that pipeline, the consequences appear later. Exploration activity weakened, reserve replacement disappointed and reserve life fell to around seven years.

The decision was seriously damaging for shareholders because BP surrendered option value before the future was known. It treated decline as a strategy, then discovered it still desperately needed the business it had planned to shrink. The 2025 reset recognises the problem and BP is increasing activity again, considering regions where it has no current production and rebuilding its exploration and appraisal programme. It has a great deal of catching up to do.

Bumerangue in Brazil is very encouraging, but it is still early. Reservoir continuity, fluid properties, carbon dioxide management and development economics need to be established. BP has found something potentially important. It has not yet proved that it has created a commercial project. After Macondo, the transition strategy and repeated governance problems, the board has limited room for another strategic error. BP still contains exceptional technical capability. The question is whether its governance can give that capability consistent direction for long enough to matter.

From 2023 to 2025 Shell spent more on exploration than the other companies in the group and reported far more exploratory well outcomes. Over five years it tested 29 plays in 15 countries.

Shell's explorers were still taking risk. The problem was conversion. Reserve life has fallen from more than 11 years in 2014 to less than eight, while recent extensions and discoveries replaced only a small proportion of production. Disposals explain part of the decline and reserve accounting is never a clean measure of exploration. Even so, the direction is uncomfortable. Shell did not stop drilling. It failed to turn enough of that activity into commercial resource renewal.

Namibia illustrates the problem. Shell drilled ten wells, found hydrocarbons and committed serious capital to understanding a difficult new basin. Reservoir quality, fluid behaviour and development pathways have so far prevented an economic project. That is not failure of intent. It is intent without sufficient conversion. On this evidence, Shell appears to have lost its way in exploration. The focus on LNG, advantaged gas, cost reduction and competitive shareholder returns is fine, but not at the expense of replacing reserves. The danger is that the market rewards the cash, then deserts the shares when the consequences of a shrinking resource base become impossible to ignore.

Depletion is patient. It does not care that the share price is strong or that a buyback was well received. Shell can satisfy the market for a time, but a weak medium term resource position will eventually become harder and more expensive to repair.

Chevron is the clearest example of buying resource depth. Noble Energy, PDC and Hess brought producing assets, development options and large inventories. Hess also brought a 30 percent interest in Stabroek, giving Chevron access to Guyana after the play had already been opened and substantially derisked.

Chevron bought barrels it had not found, but there is nothing inherently wrong with that. A company should compare the risk, time and cost of finding a resource with the price of buying one that is already discovered or producing. Buying excellent inventory can be entirely rational. Chevron's recent reserve growth nevertheless reflects acquisition rather than exploration, and its Guyana position was purchased after the breakthrough.

Chevron's caution is understandable. Its history includes painful deep water developments and liquefied natural gas megaprojects where cost and schedule became serious problems. The lesson should be to structure and partner exploration intelligently, not to retreat from it. It would be good to see Chevron rediscover the exploration and development capability that once helped define the company.

Chevron has recently expanded conventional acreage across Brazil, Namibia, Suriname, West Africa and the Gulf of Mexico. Its Kapana well in Namibia was dry, but demonstrated a willingness to test frontier geology. Chevron is rebuilding organic options while acquisition provides immediate scale. It needs to continue.

There is no completely clean winner. ExxonMobil has the greatest play opening and the best conversion of a new province into production. Eni has the strongest repeatable system. TotalEnergies has shown that selective exploration can work when reserve depth remains strong. BP created the clearest break in continuity and has the most catching up to do. Shell retained more exploration intent than is commonly recognised, but has not converted enough of it. Chevron bought the greatest resource depth and must prove that organic exploration can again become material.

The real test is whether a company can maintain access, knowledge and the appetite to create opportunities, then connect that capability to an organisation able to develop them profitably. Exploration without conversion is an expensive technical exercise. Development without exploration becomes the gradual consumption of old inventory. Acquisition can bridge the gap, but puts the future in the hands of sellers and requires the buyer to pay for risk somebody else has already removed.

The majors once responded to the loss of their greatest concessions by entering difficult offshore provinces, creating technology and committing capital on a scale that changed the industry. Later generations moved production into deeper water, beneath salt and through complex global gas chains. There is justifiable pride in what those organisations built.

They also made serious mistakes. The boom before 2014 created momentum, poor projects and damaged returns. The retreat that followed was necessary, but in places it cut beyond waste and removed capabilities that had taken decades to assemble. Covid and transition enthusiasm accelerated decisions whose consequences are only now becoming visible.

The industry is rediscovering that exploration cannot be restarted by changing a line in a presentation. Attractive acreage, good ideas, basin knowledge and experienced teams take time. The companies that preserved them have more choices. Those that allowed them to weaken are rebuilding while quality resources remain scarce.

The European majors made the larger strategic errors during the transition, but the Americans should not congratulate themselves too quickly. ExxonMobil and Chevron rely heavily on the Permian. Shale is valuable and flexible, but its decline rates create a drilling treadmill. It is not a complete long term substitute for discovering large conventional resources.

Every major in this group still has work to do. ExxonMobil must build beyond the success of Guyana. Chevron must restore organic exploration without repeating the excesses of its old megaprojects. Shell seems to be pretending that advantaged gas and cost cutting are an acceptable alternative to replacing reserves. It must convert more of its activity into commercial resources. BP must rebuild continuity and credibility. TotalEnergies must ensure selectivity does not become scarcity. Eni must keep proving that its model is repeatable.

Exploration has changed, but its strategic purpose has not disappeared. A major still needs to create resource options before it needs them, decide which risks are worth taking and convert discoveries into durable returns. The strongest companies will know when to drill, when to buy and when success in one basin is becoming an excuse not to find the next one.