The oil price crash of 2014–15 sparked a difficult recalibration between upstream oil revenue and oil field development costs. The slowdown in upstream activity led to an oversupply in the markets for equipment, materials, and labor—and thus the costs of these inputs declined dramatically. Oil producers have built on these savings by improving the way that they design, build, and operate new projects and giving the green light to only the most economic projects in their portfolios. In short, operators are seeking ways to achieve higher return on their selected investments—or, in other words, to produce more for less.
Since 2014, the “cost of oil”—the oil price needed to justify investment—has fallen across the board, but by different degrees depending on the geography and type of development. IHS Markit recently surveyed how costs have changed across five key global oil supply sources: Canadian oil sands steam-assisted gravity drainage (SAGD), global deep water, Middle East onshore, Russia onshore, and US tight oil. Among these sources, we estimate that the full-cycle cost of a “representative” new oil project fell by a production-weighted average of about 34% between 2014 and 2016. In 2016, the break-even price of a representative project in terms of Dated Brent ranged from less than $15/bbl for Middle East onshore to roughly $40/bbl for global deep water and US tight oil, about $45/bbl for Russia onshore, and just over $50/bbl for Canadian oil sands SAGD.
IHS Markit defines the cost of oil here as the cost of finding, developing, and then producing from new oil production capacity. We express this full-cycle cost in terms of the Dated Brent price at which a project “breaks even,” assuming a 10% internal rate of return. The goal of our analysis is to illustrate how the cost of a representative new project has changed over time in several key producing areas, rather than to compare costs among these areas or estimate an “average” cost for a particular area, given the wide variety of project attributes and full-cycle costs in each.
What forces are driving the global oil cost reset? Below are key forces that have pushed down the cost of oil around the world:
- Service sector cost deflation. As oil prices plummeted and then stayed at lower levels, upstream activity declined, and the markets for oil project inputs (including equipment, labor, and materials loosened. The cost of these inputs, in turn, fell materially.
- Improvements in how projects are designed, built, and operated. The price collapse has forced oil companies to find better ways of designing, building, and operating projects.
- “High-grading.” Companies are focusing their limited capital on advancing only their best investment opportunities. This could mean expanding existing fields, which can reduce costs by piggybacking on infrastructure already in place, or drilling only the best wells in a field that is already under development.
- Exogenous forces. In some jurisdictions, forces outside an oil company’s control, such as local currency devaluation and supportive fiscal terms, have further reduced the cost of oil.
Of note, the mix and weight of these factors on the cost of oil varies among supply sources.
Looking forward, a key question for the global oil industry is: How durable will cost savings be coming out of the downturn? The future trajectory of global full-cycle costs is not preordained. The extent that continued innovation can offset rising service sector costs will help shape the cost of oil around the world. The number of large projects sanctioned—and their break evens—will be signposts of how the industry cost structure will evolve. Indeed, the recent stabilization of global benchmark oil prices around $50/bbl is incentivizing some companies to increase upstream spending—most notably on short-cycle tight oil development in the United States.
How long this stability will endure is an open question. We currently expect upstream exploration and production capital expenditures in North America to increase by 25% this year, with the Permian setting the pace, but to be flat or lower elsewhere. We also expect costs to rise 15-20% this year in the Permian, the most active area by far, but to be relatively flat in the industry more broadly.
For oil markets, the evolution of upstream project costs has implications for the size of any supply “gap” that may (or may not) develop later this decade, or at the turn of the decade, as a result of deep investment cuts in the past two years and, in turn, for oil prices. As for oil producers, it is important to note that it is ultimately neither prices nor costs, but the difference between the two, that is paramount to project economics.
For more detailed analysis of global oil cost trends, clients can find the IHS Markit Strategic Report, "Making Ends Meet: How the oil industry is cutting costs to make up for lower prices”, on Connect. For further information on purchasing the report, contact Kent Williamson.
Jeff Meyer is an Associate Director at IHS Markit, primarily focused on the global oil markets.
Posted 16 May 2017