Offshore Development Slump Likely To Cause Long-Lasting Pain

Offshore exploration will be slow to come back as companies have delayed billions in projects through 2020. Exploration projects also must complete for funds with brownfields developments like EOR that potentially provide a shorter time to show a return.

Capital spending is expected to continue falling in the near term.
Graphic courtesy of Wood Mackenzie.

Those waiting for the offshore exploration sector to come back should expect delays. “We are at the bottom of the cycle,” Julie Wilson, research director for global exploration at Wood Mackenzie, said during a presentation at the 2016 Offshore Technology Conference (OTC) that showed deepwater spend declining through 2020, with no upturn in sight.

The problem is that an oil price of USD 50/bbl is still short of the price needed to profitably develop deepwater fields. An oil price of USD 60/bbl is the break-even cost for 70% of the proposed deepwater projects, she said.

The energy information company predicted a growing backlog of postponed projects in the coming years, totaling USD 150 billion by 2020, in a sector where future investment will be affected by whether it can break from its reputation for high costs.

Deepwater producers have made progress in cost cutting. Despite the drop in hydrocarbon prices since 2013, the gap between the value of what has been discovered and the cost of finding and appraising those fields has narrowed. But the deficit remains significant.

“Hammering the service sector will not make projects viable again,” Wilson said. While service companies and suppliers cannot afford further discounts, savings are possible because, she said, “there is huge waste across the industry.”

For example, projects to build the trains used to liquefy natural gas have had huge cost overruns. Those high-development prices combined with depressed prices for natural gas worldwide led to the deferral of USD 43 billion in deepwater projects in Australia, and USD 37 billion in Mozambique.

Lowering offshore costs, though, will require more than better project management. The rising costs also reflect rising numbers of dry holes. The drilling success rate dropped from 40% to 35% between 2012 and 2015, as the industry went after prospects in increasingly complex formations.

Some discoveries have proven too costly to develop because the fields were in remote areas where the cost of installing production facilities was too high, or there were problems to solve, such as high-temperature/high-pressure reservoirs.

The value of discoveries has been less than the cost of exploration and appraisal costs since 2013. Graphic courtesy of Wood Mackenzie.

Even if oil prices rise above USD 60/bbl long enough to alter industry expectations about future price trends, those fields will be competing with development alternatives such as onshore unconventional plays. For example, Chevron’s Buckskin/Moccasin offshore project in the Gulf of Mexico is expected to produce oil for about USD 62/bbl, while the company’s best unconventional wells in the Permian Basin deliver at about USD 40/bbl, and do not require the long-term commitments of deepwater field development.

Offshore exploration is also competing with investment in older fields. For example, Anadarko estimated it would earn a 34% return by adding production with infill wells at its Lucius Field in the Gulf of Mexico, according to the presentation.

Brownfield investments, such as enhanced oil recovery (EOR), are also likely to become an increasingly significant source of added barrels. In a presentation at OTC, BP talked about why it sees a payoff in large technology development investments in low-cost EOR as well as improved seismic imaging, which can highlight remaining opportunities in older fields.

Deferred capital expenditure by country in USD billion. Graphic courtesy of Wood Mackenzie.

“By applying the best technology in the best giant fields you can add a lot of value in the next 25 years,” said Ahmed Hashmi, global head of upstream technology for BP.