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Sunken cost fallacy?

Offshore explorers have hammered away at costs in recent years, but that doesn't mean deepwater earnings can thrive if prices stay at their current levels
July 6, 2017

In 2014, oil used to sell for more than $100 (£77) a barrel. Three years on it trades just below $50, at a level many in the industry - however shortsightedly - have termed the 'new normal'. While this constitutes an enormous lowering of explorers' profit expectations, the reset in prices hasn't rendered any one form of drilling entirely unprofitable. Even the prospect of expensive and technically challenging production in the Arctic - thought to have been extinguished by Royal Dutch Shell's (RDSB) failure in Alaska's Berger field - is back on the table, after Norway last month opened up 93 blocks in the Barents Sea area for exploration.

However, not all oil projects are created equal. Despite their best offers to cut costs, producers focused on offshore and deepwater drilling are treading a very fine line. And, despite serious pressure on the oil services sector (see box), break-even prices remain higher than conventional onshore production. Depending on project specifics, offshore drilling tends to carry longer payback timescales.

This market dynamic explains several of the oil majors' cautious and selective attitudes towards offshore projects in the past two years. But there are signs that this trend is slowly reversing.

At the end of 2016, BP (BP.) sanctioned the Mad Dog 2 project in - of all places - the Gulf of Mexico, in a move the company said demonstrated its "long-term commitment to the region despite the current low oil price environment". The project, in which BHP Billiton (BLT) is a 24 per cent stakeholder, will produce up to 140,000 barrels of crude a day from a floating production platform tied to 14 wells. Its $9bn price tag also comes in at less than half the original forecast development cost, after the platform was totally redesigned.

Not one to be outdone by its London-listed rival, Shell has given the green light to one of its own Gulf of Mexico projects: Kaikias, an oil and gasfield that will be commercialised through a subsea tie-back to the nearby Shell-operated Ursa production hub. In both cases, investors have been assured that there are profits to be made from the fields at $40-a-barrel oil, although the sales pitch has subtly shifted - in the words of BP chief executive Bob Dudley - to "value over volume".

If you take into account the massive upfront capital burden, together with the hefty operational (and decommissioning) costs of offshore production, such pledges are impressive. How has this been achieved? In the case of Mad Dog 2 and Kaikias, it is a combination of creative engineering, through the use of subsea tie-backs and hub facilities and the preparedness of Gulf of Mexico-based services companies to reduce prices.

Globally, there is scant evidence of this combination of cost reduction and portfolio high-grading. According to analysts at Wood Mackenzie, the average pre-sanction deepwater project carries an average break-even cost of $62 per barrel of oil equivalent (boe), based on a 15 per cent discount rate to the project's net present value. That's down from $79 a barrel in mid-2014, but still above the levels needed for capital markets or boards to provide funding with any degree of confidence.

Waiting for higher prices to come back is hardly the answer to the problem of offshore drilling. Higher prices will only inflate costs, as many are predicting for the US shale industry over the next two years. But aside from the temporary help provided by lower rig rates, Wood Mackenzie believes operators can help themselves by reducing projects' facility size, processing capacity and well count. If these costs come down by another 20 per cent, this would put "around 15bn boe in the money at $50 a barrel", putting deepwater projects on a level pegging in the hunt for risk capital, and ahead if cost inflation returns to the key US shale basins, as many are expecting.

Offshore projects' falling costs

This will be forefront in the minds of the board of Cairn Energy (CNE), which will next year reach its final investment decision and development concept for its Sangomar Deep (or 'SNE') discovery off the coast of Senegal. Exploration at the field has yielded nine successful wells in the past three years, and represents potential gross resources of at least half a billion barrels of oil equivalent. According to analysts at Macquarie Research, the field should be highly commercial at low oil prices - potentially returning a free cash flow yield of 29 per cent a year once on stream. In the near term, huge savings to two other projects - Kraken and Catcher in the North Sea - should start to generate returns once the fields come online.

Favourites

Faced with high upfront costs and limited cash, Ophir Energy (OPHR) provided another example of how to get a difficult offshore project over the line. In May, the company finalised the terms of its Fortuna liquefied natural gas development offshore Equatorial Guinea, in a joint venture with Schlumberger, Golar LNG and the Guinean government. Although Ophir has sacrificed a good chunk of Fortuna's eventual cash generation and will receive debt funding from a consortium of Chinese lenders, the company will not incur "any additional balance sheet exposure or liabilities". The net present value of Fortuna should also represent a "healthy multiple" of the $120m (£99m) it has committed before first gas.

Outsiders

Can the same trick be repeated for the Sea Lion field, majority-owned by debt-laden Premier Oil (PMO)? Venture partner Rockhopper Exploration (RKH) certainly hopes so, given that the smaller group's fortunes are heavily tied to commercialisation of the North Falklands Basin discovery. In a recent update on the project's front-end engineering design, Rockhopper said "a number of contractors" and "potential providers of export credit finance" had expressed an interest in funding the project ahead of its sanction next year. As we have previously flagged, the project's mooted $45 break-even price will be a huge test of potential venture partners' willingness to take a long-term view, let alone stomach the region's complex geopolitics.