Global offshore oil struggles to find its footing: Fuel for Thought

Global offshore oil production has been the most sluggish and recovery resistant sector in the oil industry during the last three years of slumped oil prices, but the arena is showing signs of adaptation and resiliency thanks to new cost-paring measures that in some cases allows offshore projects to compete with shale.

The need to reduce costs is not only critical for private companies and national oil companies. The world needs oil from those projects to meet future demand.

"The offshore sector, which accounts for almost a third of crude oil production and is a crucial component of future global supplies, has been particularly hard hit by the industry's slowdown," the International Energy Agency said in a recent report.

"In 2016, only 13% of all conventional resources sanctioned were offshore, compared with more than 40% on average between 2000 and 2015," IEA said.

As the industry adjusts to what could be a lower-for-longer oil price and what investment bank Barclays has called a "new oil paradigm," the offshore sector is becoming more compact, nimble and phased, Barclays analyst David Anderson told S&P Global Platts.

Breakeven prices for offshore projects generally are around $50-$60/b, analysts say, higher than world oil prices which have hung in the mid-$40s/b to low-$50s/b in the last year.

As a result, operators are being forced to adjust their thinking in a changing industry where speed, flexibility and economy are crucial.

As the industry moves into a third year of lower oil prices and Brent prices linger at or below $50/b, a mere handful of offshore projects have been sanctioned recently.

Many producers have shelved exploration in favor of quicker-return US shale onshore. Those still with an offshore presence are straining to whittle down the cost of commercializing pricey discoveries made years ago at $100/b oil and find new fields to bring online at current prices.

By end of April, seven offshore fields worldwide had been approved in 2017 that will add 500,000 b/d of oil equivalent production by 2020, according to researchers at Bernstein Energy.

But six of the seven are tiebacks "hookups to existing production facilities that will yield less than 50,000 boe/d each," Bernstein said in its most recent monthly Offshore Activity Monitor.

There have been two more final investment decisions since then.

Tiebacks typically yield less crude oil than greenfield projects that tend to produce around 75,000 boe/d, but they are cheaper and faster to bring online.

One of this year's sanctioned new projects is Shell's Kaikias, in the US Gulf of Mexico.

Peak first-phase production will be 40,000 boe/d from the project whose first oil is expected in 2019.

Kaikias, which holds more than 100 million boe, has a breakeven price under $40/b, the major said when the project was sanctioned in February.

Shell will use what it calls a "simplified" design, producing through its nearby operated Ursa field hub which should reduce total costs 50% compared with initial estimates.

The company did not immediately unveil that cost, but Bernstein, using data from energy consultants Wood Mackenzie, estimated it at $1.35 billion.

COST CUTTING

Analysts say costs are being lowered in different ways. Greenfield stand-alone design concepts are being reworked, streamlined and planned in incremental stages, as BP has done with its Mad Dog Phase Two development in the US Gulf of Mexico deepwater.

There, the production facility was pared down in size and number of producing wells, for example.

While interest is growing in technologies in data analytics, sensors and artificial lift, operators are also mitigating costs by renegotiating contracts with service providers as was done at Mad Dog 2, said Harshit Sharma, a research associate at Lux Research.

Bernstein last week interviewed David O'Connor, BP's head of global projects, who said the major has saved 30%-40% on subsea services and equipment through competitive bidding.

Also, subsea vessel costs have dropped about 20% in the last year or so from an industry surplus competing for limited work, according to Bernstein's transcript of its interview.

And by getting suppliers involved early in the production hub design process, they can better employ standardized equipment in a project, O'Connor said.

This worked well for Mad Dog 2, sanctioned last December. The field, originally discovered in 1998, has produced since 2005.

But next-phase development was paused four years ago as offshore costs shot up, and the major shifted its ideas for producing the field. BP has said Mad Dog 2 can now break even at around $40/b.

"The initial concept was a 'big dog' spar of 50,000 tons," BP spokesman Jason Ryan said. But in the end, the company went with a new floating production platform that could pump 140,000 b/d of oil.

The number of wells was cut back from 33 down to 14 production and eight water injection wells.

The result: "A headline $20 billion project became a $9 billion project," O'Connor said.

Shell and BP are still the exceptions, Bill Ebanks, managing partner for turnaround consultants AlixPartners, said.

"When prices get to a predictable $60/b to $70/b, we'll see domestic offshore activity pick up in a meaningful way," he said.

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