In the depths of the ocean off the coast of Uruguay, more than two miles below sea level, the oil industry is continuing to push back the frontier.
Last month a drillship operated by AP Møller-Maersk of Denmark began the Raya 1 well in 3,411 metres of water, breaking the record for sea depth previously set in 2013.
Drilling in such extreme conditions is a remarkable feat, but wells such as Raya 1 are becoming increasingly rare. Technology makes them possible, but economics militates against them.
For the companies that operate offshore rigs on behalf of oil producers — including Transocean, Seadrill, Ensco and Noble Corp — the slump in crude prices since the summer of 2014 has been brutal. They have been reporting large losses, and have cut or scrapped their dividends. Their share prices have plunged.
The impact of low oil prices is often depicted as a battle between Saudi Arabia and the onshore shale producers of the US. But other relatively high-cost sources of supply around the world have also been hit, and for offshore oil the effect is likely to last longer.
The latest data for offshore oil and gas production still look healthy. Last year output from the UK sector of the North Sea rose 7 to 8 per cent, while crude production in the US waters of the Gulf of Mexico rose 10 per cent.
That growth is the result of decisions taken years ago, however. Matt Cook of Douglas-Westwood, a consultancy, says that because offshore projects take years to develop, the impact of falling oil prices is felt only after a lag.
“This hasn’t yet got as bad as it could well be,” he adds. “Some of the positive moves we have seen in drilling are the result of decisions that were committed to before the downturn. It’s quite possible that the worst is yet to come.”
The number of drillships and “semi-submersible” floating rigs working around the world has dropped from 251 in September 2014 to 169 last month, according to the RigLogix database from Rigzone, a research firm.
Only a handful of new offshore projects were given the green light last year, including Royal Dutch Shell’s Appomattox in the Gulf of Mexico, Eni’s OCTP off the coast of Ghana, and Statoil’s Johan Sverdrup field in the Norwegian sector of the North Sea.
Even more ominously for the contractors, many oil producers have cut back sharply on exploration to find fields that will lead to future developments. ConocoPhillips of the US said last year it would pull out of deepwater exploration altogether by 2017.
Paal Kibsgaard, chief executive of Schlumberger, the world’s largest oil services group, on Friday told analysts that its customers showed signs of “facing a full-scale cash crisis”, and in the second quarter their spending was likely to be even lower than in the first three months of 2016.
One particular weak spot for Schlumberger was sales of offshore seismic survey data — essential for exploration — which Mr Kibsgaard said had fallen to “unprecedented low levels”.
With cash flows under extreme pressure, and commitments to investors that dividends will not be cut, oil companies see little benefit in spending money on exploration that might at best pay off in production 10 years from now.
The slowdown in both exploration for new fields and the development of past discoveries is causing particular difficulties for those rig operators that are heavily indebted.
For example, Seadrill’s net debt was 4.7 times its earnings before interest, tax, depreciation and amortisation in 2013, before oil prices slumped, and at the end of 2015 the company’s leverage had increased to 5.4 times.
Noble and Transocean have had their credit ratings cut from investment grade to junk status as a result of the downturn.
Jeremy Thigpen, the new chief executive of Transocean, stressed the company’s financial strength and its ability to ride out the downturn at a conference last month.
But Transocean’s regular fleet status report last week showed that of its 28 rigs capable of working in “ultra deep” waters, just 12 were under contract, with the rest “stacked” or idle.
Not every company is turning away from offshore oil and gas. Total is leading the Raya 1 project in Uruguay. Shell said the potential for growth in deep water off Brazil was a central reason for its £35bn takeover of BG Group.
Although offshore and especially deepwater oil is expensive, the fields found can be very large. So the cost per barrel is not necessarily higher than for US shale, says Amrita Sen of Energy Aspects, a consultancy.
The big difference, however, is in flexibility. Offshore, a well might cost $100m and take many weeks to drill, while onshore it will cost about $5m to $7m and take less than two weeks.
That means shale operations can be adjusted quickly to respond to changing market conditions. If you commit to a big offshore project, you are pretty well stuck with it, even if falling commodity prices make it uneconomic.
“The problem is not just that oil is at $45,” says Ms Sen. “It’s that you just can’t be certain of anything.”
ExxonMobil told investors last month that it was pursuing “several” offshore development opportunities. However, executives also stressed the flexibility of its US onshore assets, which would allow them to ramp up production quickly if oil process rise.
Mr Kibsgaard of Schlumberger suggested on Friday that this would be a common view across the industry. Large new offshore projects, he said, were “not going to be the first area that our customers are going to start putting money into“.
When the recovery comes, he added, investment will pick up onshore first and offshore — and especially in deep water — only later.
That means the financial pressures on the rig companies will continue, potentially with significant low-term consequences.
Keeping a modern drillship “hot stacked” — ready to move off to a job if needed — can cost $150,000 per day, according to Antoine Rostand, president of Kayrross, an energy technology start-up. That creates an incentive for the operators to scrap or sell rigs, rather than retain them to wait for the upturn.
There is a widespread expectation that as oil prices recover, the US shale industry will spring back to life. If, for whatever reason, that fails to happen, then it will take a long time for the offshore industry to be revved up to fill the gap. The result could be a surge in oil and gas prices, at least for a while.
“This is a dangerous game for the industry,” says Mr Rostand. “The knock-on effect of reduced activity on the industry will be prolonged.”
This is the seventh part of a Financial Times series entitled Oil: Lower for longer, looking at the consequences of the fall in crude prices.
Although most of the news for the offshore oil industry is bad, there is one silver lining: projects that were prohibitively expensive might now be able to go ahead, because costs have fallen so far.
BP’s proposed Mad Dog 2 project in the Gulf of Mexico, an extension to the Mad Dog development that started production in 2005, originally fell victim to soaring costs.
The original complex design was rejected back in 2013, even before oil and gas prices started their big fall, because its sky-high costs made it financially unattractive.
Engineers from BP and its junior partners in the development, Chevron and BHP Billiton, went away and came up with a new plan, and with the help of the extra leverage provided by the slump in oil prices the cost of the project has been cut in half.
Lamar McKay, BP’s deputy chief executive, said at the IHS CeraWeek conference in February that the original estimate of the cost of Mad Dog 2 had been $20bn, and it was now less than $10bn.
The new design would be more profitable with oil at $60 per barrel than the old one would have been at $100, he added.
However, although BP says that the project is now commercially attractive and will go ahead at some point, it has still not actually made the commitment to invest in it.
As Mr McKay told the Financial Times in February: “The project will be sanctioned. It’s just a question of when.”
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