Exploration’s future in a low-cost, low-carbon world

The unmet oil and gas supply opportunity is huge

Exploration competes with other greenfield and brownfield resources to meet future supply needs. The huge opportunity for new volumes depends largely on two big unknowns: firstly, demand through the energy transition and, secondly, supply from onstream fields. 

The pace of the energy transition is uncertain, even assuming an eventual recovery from the current crisis. Wood Mackenzie considers three possible demand scenarios for the longer term:

• The energy transition outlook (ETO) represents our base case view of the energy world, broadly consistent with a 3°C global warming view.
• The accelerated energy transition (AET) represents how the world can accelerate decarbonization to around or just below 2.5°C of warming.
• The accelerated energy transition 2-degree scenario (AET-2) represents how the world can augment efforts towards deep decarbonisation with a credible pathway to reach a 2°C global warming trajectory by 2050.

The implications for oil and gas are vast. Cumulative demand to 2040 under our ETO scenario is almost 200 billion barrels of oil and 100 billion boe of gas higher than under our AET-2 scenario.

Near-term demand depends on how the world recovers from the pandemic crisis and how OPEC+ manages supply. But long-term fundamentals are not so different in our initial analysis of energy demand post-Covid.

We see as much uncertainty on the supply side. Most upstream capital investment in our base case is uncommitted and might never happen. The majority of this spend – almost US$4 trillion over the next 20 years – goes to sustaining output from fields already onstream.

As soon as the industry steps off its investment treadmill, production from onstream fields falls fast. We estimate average annual decline rates of 8% for oil and 6% for gas. A nil-investment scenario cuts more than 200 billion barrels of oil and 100 billion boe of gas from our base case supply by 2040.

No shortage of resources vying for investment

Global remaining oil and gas resources exceed three trillion boe, not counting new exploration. Clearly, the world already has abundant discovered volumes technically capable of meeting even our highest demand outlook until well beyond 2040.

But advantaged resources are not so plentiful. We identify 1,400 billion boe of oil and gas that are best placed to meet our ETO demand outlook to 2040. These span a mix of brownfields, greenfields and exploration.

The industry has always prioritised low-cost resource and projects with the best economics. Tighter capital discipline has led to an even more rigorous definition of advantaged resource, while ESG criteria add another layer of scrutiny.

The industry typically illustrates future supply with an implied sequencing in order of field development status, beginning with onstream and ending with exploration. Such ranking is not how it works in practice. Each status holds individual assets with a wide range of different costs and economics. It is not true that incremental brownfields are invariably best.

Exploration’s costs of supply can be competitive

The most advantaged barrels – simply put, those with the lowest point-forward costs – flow from onstream fields without future capital investment. This proven developed supply has short-run marginal costs that are less than half the cost of volumes requiring capital investment. All current production is in this category but it declines fast and will supply only 44% to 57% of oil and 48% to 58% of gas to 2040.

The other half of supply requires capital investment. These resources show surprisingly little variation in average costs by development status: all the various categories of greenfield and brownfield fall within the narrow ranges of US$16 to US$18/barrel for oil and US$11 to US$13/boe for gas. These costs include exploration, appraisal, development, production and abandonment.

Exploration must overcome three challenges not faced by other resource options:

• Discovery costs
• Subsurface risk and dry holes
• Longer cycle times

Only about one exploration well in six results in a commercial discovery. This subsurface risk adds to discovery costs that average around US$2/boe. Even including unsuccessful efforts, such costs are only a modest component of full-cycle breakeven prices, unless compounded by exceptionally long lead times.

Exploration does have longer cycle times compared to brownfields. The industry has made great progress on this front over the past decade by increasing its focus on prospects with a clear path to commercialisation. Production from discoveries completed between 2010 and 2019 will peak 10 years quicker than from the previous decade’s exploration.

Despite these extra burdens, exploration’s costs are competitive because alternatives have higher development costs. Explorers, on average, find better resources than the legacy assets that still await development. 

Leapfrogging up the pecking order has always been the story as new exploration plays emerge. Rapid discovery-to-production projects like Zohr (gas) and Liza (oil) prove it’s still happening today.

Most of the easy brownfield opportunities are in the past

There are few easy options among the various alternatives to exploration. Greenfield costs for discovered pre-FID resources are highly variable, but often challenging. Unsurprisingly, old discoveries that have lain fallow for many years are rarely advantaged. The rewards of investment in such high-breakeven assets are far from guaranteed. Many also face subsurface uncertainty that can be comparable to exploration risks.

Likewise most potentially commercial but as yet undeveloped tight oil plays. Russia’s Bazhenov shale, often cited as one of the world’s most promising plays outside North America, illustrates the challenge. Despite in-place resources of more than two trillion barrels, we estimate costs may exceed US$60/barrel so exploration of the play remains at an early stage.

Incremental brownfield volumes from onstream fields are the largest opportunity. But these barrels are often expensive, despite existing facilities and infrastructure. These fields’ initial development phases have already captured the easy barrels and new work to boost recovery faces the law of diminishing returns.

New technologies such as digitalisation could be a game-changer for field recovery< rates. Gains could improve development economics for brownfields and greenfields alike. Of course, any such wins would similarly enhance exploration economics by boosting the value of new discoveries.

Some of the best brownfield opportunities are where appraisal work proves new in-place volumes (for example, Mad Dog in the US Gulf of Mexico) rather than investments to improve recovery factors. 

Secondary recovery work to support reservoir pressure using technologies such as water injection, gas reinjection and gas lift can be an economic sweet spot. But these techniques have been available for many decades so attractive, material opportunities are now scarce. Much more common are smaller infill drilling options. These wells typically target marginal parts of the reservoir and add higher cost volumes.

Enhanced or tertiary recovery to increase mobility of the oil within the reservoir is particularly costly. Key technologies of gas injection, steam flooding and chemical injection are usually only viable onshore. One of the largest examples underway outside of the United States is PDO Block 6 in Oman which increasingly depends on tertiary recovery to sustain output from fields already onstream for over 50 years. Around three billion barrels of oil remain but with average capital and operating costs of US$28/barrel.

One intriguing possibility is the potential for wider use of CO2 miscible flooding to support carbon capture and underground storage. Carbon-pricing incentives could help reduce the costs of this technology in the future.

Key battlefields for advantaged resources

Almost all low-cost resources will be produced, while most high-cost resources will remain in the ground. It is the opportunities with intermediate costs that could go either way.

Our highest oil demand scenario (ETO) requires 840 billion barrels production by 2040:

• Most advantaged are 330 billion barrels costing less than US$10/barrel. These are mainly proven developed resources. Just 2% are exploration opportunities
• Next in line are 360 billion barrels costing US$10 to US$20/barrel, likely to be the key battlefield for new opportunities. At least 90% of these volumes will be needed, even under our AET-2 demand scenario. Exploration represents 25% of these mid-cost resources
• Lastly, 150 billion barrels cost above US$20/barrel. Exploration represents 27% of these higher cost resources. These are not required under AET-2.

Our highest gas demand scenario (ETO) requires 550 billion boe production by 2040:

• Most advantaged are 360 billion boe costing less than US$10/boe. These are largely proven developed resources. Less than 10% are exploration opportunities
• A further 175 billion boe cost US$10 to US$20/boe, likely to be the key battlefield. Only about half will be needed under our AET-2 demand scenario. Exploration represents 25% of these mid-cost resources
• Just 25 billion boe cost above US$20/boe, with this high-cost gas likely to struggle

The case for future exploration

Exploration can play its part within a balanced renewal strategy, creating value with full-cycle costs and risks that are competitive against greenfield and brownfield alternatives.

Great changes are sweeping the upstream industry, from digitalisation to ESG scrutiny. None poses any particular threat to exploration over the rest of the upstream business.

New development and production technologies will boost field economics, driving down costs and helping recovery factors on their upward trend. Such gains apply equally to exploration, enhancing brownfields and new fields alike.

Reporting of comprehensive, transparent and consistent ESG performance will become obligatory and universal. Carbon metrics can be a catalyst for portfolio change as assets with poor emissions fall from favour. Carbon could encourage new greenfield opportunities, including exploration, in a drive to displace disadvantaged older assets.

Companies have been sending mixed signals. Many, such as the European Majors, are allocating more capital towards new energy which might directly reduce exploration spending in future. At the same time, most Majors, leading E&Ps and many NOCs are continuing with high-impact wildcatting and exploration new ventures.

There is plenty of headroom. The global exploration industry is unlikely to overwhelm its potential opportunity even if it rebounds quickly back to its recent scale. Long-term oil fundamentals remain strong and supply depends on future capital investment. Perhaps under-investment in exploration might eventually cause price spikes. More likely is a growing pivot to exploration from NOCs, eager to capture an opportunity from any retreating IOCs.

Most companies efficiently exploit their advantaged resources first and thereby erode their portfolio quality. Those wishing to remain in the upstream business must invest to replenish their depleting asset base. For companies with the requisite skills and appetite, exploration is as good an option as any. 

To paraphrase Dr Samuel Johnson, when a company is tired of exploration, it is tired of oil and gas.

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