What’s the marginal cost of oil supply – $60/bbl or $80/bbl?

Much has been written lately about the falling marginal cost of crude supply, as breakeven costs for US shale continue to fall. Last week, Goldman Sachs cut its Brent oil price forecast to $65/bbl in 2016-18 and to just $55/bbl in 2020, well below consensus and the long-term forward curve. The bank argues that US shale breakeven costs have dropped by $20/bbl in a year thanks to structural efficiencies and productivity improvements. The global oil curve has become flatter and lower, and growth from US shale and OPEC is enough to meet demand growth to 2025, the bank argues.

Exhibit 1: Oil cost curve has shifted lower and flatter due to US shale

Exhibit 2: Breakevens of non-producing and recently on-stream oil assets

Source: Goldman Sachs Investment Research

We have a lot of sympathy for GS’s argument that US shale has fundamentally reshaped the global oil cost curve. It is now widely accepted that US light tight oil economics are generally more robust than many other sources of non-OPEC incremental supply, notably (ultra) deepwater and oil sands. Deepwater and oil sands have thus been duly pushed to the right of the cost curve and a myriad of deepwater and oil sands projects have been delayed.

Exhibit 3: Estimates of long-term breakeven costs for various project types

Source: Estimates of long-term breakeven costs for various project types

Shale breakevens in the top basins (Bakken, Eagle Ford and Permian) are well below the $80-100/bbl often required on deepwater, oil sands or enhanced recovery projects. To quote a few examples, Bakken producer Continental Resources expects average IRRs of 40% at $60/bbl assuming a 15% reduction in costs. If we assume a more reasonable minimum target return of 20%, Continental’s oil price breakevens range from $50-60/bbl in the Bakken down to $30-40/bbl in the more profitable SCOOP (Oklahoma Woodford) shale. (These are quoted in local oil prices, which trade at a discount to Brent). Permian producer Concho Resources sees 50-60% IRRs at $60/bbl in the Permian basin with enhanced completions, implying low breakevens well below $50/bbl for a target 20% IRR.

Exhibit 4: Continental Resources’ view on rates of return in the Bakken and SCOOP at various oil prices

Source: Continental Resources (April 2015). Note: CWC is completed well costs.

One important caveat is that shale break-evens are highly variable by play and county. The chart below from Wood MacKenzie shows significant variability in liquids-rich shale breakevens, ranging from $30/bbl to $130/bbl in the Eagle Ford. North Dakota’s Department of Mineral Resources estimates break-evens in core Bakken counties at just $29-41/bbl, compared to $44-75/bbl in non-core areas.

Exhibit 5: Shale break-evens show wide variations by play, sub-play and county

Source: Wood Mackenzie (March 2015). Note: Break-evens calculated as oil price required for a 10% IRR

Meanwhile, typical deepwater projects (if there is such a thing as a “typical” deepwater project) such as those in the US Gulf of Mexico or West Africa require around $80-90/bbl in a 2014 cost environment, and costs aren’t coming down particularly fast. Lower service costs and smart re-engineering in the pre-FID phase could theoretically decrease these break-evens by, say, $10-15/bbl to a more palatable range of $65-80/bbl. Majors have asked for significant price reductions (20-30%) from their suppliers; but while drilling day-rates and seismic costs have fallen substantially (35-50%), subsea and platform construction costs have yet to come down materially. One exception is the Brazil pre-salt, with all-in supply costs of $40-45/bbl according to Petrobras, although this guidance is before cost overruns and delays.

If low-cost shale and OPEC can indeed meet all of the world’s needs – and this is a big if, it begs the question of whether the world still needs expensive projects.

In a world with no natural depletion and no demand growth, expensive projects such as oil sands and ultra-deepwater should simply not be needed, and the shale revolution would push down the long-term oil price to the $55-65/bbl level that GS has talked about.

However, the reality is that the industry needs to put onstream c 4mb/d of new production just to stand still given natural decline rates and c 1.1mmb/d of annual world demand growth. We are doubtful that OPEC and even a buoyant US shale industry can together produce 4mb/d of liquids growth per annum.

Exhibit 6: Global liquids supply & demand – each year, new fields need to offset decline and rising demand

Source: Chevron (March 2015), from IEA World Energy Outlook

The charts below illustrate the enormity of the task at hand for the global oil industry. More than half the world’s oil is produced from fields already in decline, where underlying decline rates are typically 10-15% (ex-reinvestment) and probably closer to 4-6% post-reinvestment.

As Exhibits 7-8 shows, most of the non-OPEC world’s mature or “legacy” production in terms of size is in Russia, China, Mexico, Brazil, Canada, the North Sea and central Asia, where decline rates range from 6% for the big onshore producing countries up to 15% at the top end for offshore and deepwater.

Exhibit 7: Declining production capacity by country in mb/d (2014 estimates) – more than half the world’s oil is produced from fields already in decline

Source: Credit Suisse estimates, based on Wood Mackenzie (January 2015)

Exhibit 8: Underlying decline rates of producing fields are typically 10-15%

Source: Credit Suisse estimates, based on Wood Mackenzie (November 2014)

In conclusion, North American shale alone is unlikely to have shifted the entire global cost curve much below $80/bbl in the long run. Time will tell whether Goldman – which famously called for $200/bbl oil in the 1H 2008 bull run – or us will be proven right.