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Leading oil majors are expected to increase their exploration capital expenditure (CAPEX) by 20 to 30 percent next year, resume drilling in deepwater in a bid to build hydrocarbon-based assets, said John Jeffers, Group Development Director for Oil & Gas at SNC-Lavalin.
Jeffers sees asset swaps among the majors, with a good level of acquisitions of reserves from medium or small holders in the industry. Companies are more efficient having slashed capital expenditures (CAPEX) and operational expenditures, added Jeffers.
“Oil majors can no longer stay away from building reserves,” Jeffers told Rigzone at the Singapore International Energy Week, adding it is a matter of their standing in the global businesses.
Opportunities are there as daily rig rates are at $50,000 to $60,000, down from the $120,000 peak seen several years ago, according to sources at rig-builders.
Deepwater hydrocarbon production and ultra-deepwater exploration will remain in the ground for a longer while. It is only viable at a sustained barrel price of $60 to $65 and he sees 2018 oil prices range between $52 to $58/bbl.
A price of $60 would certainly bring back the U.S. shale oil on the international market, something OPEC would not want to see. For example, the breakeven for the Wolfcamp, Bakken and Eagle Ford basins are sub-$40 so prices above this makes them viable.
OPEC has for the first time in many decades showed strong production discipline, and this has helped maintain prices in the mid-$50s range, observed Jeffers.
Thanks to technology, shale gas from the United States has brought prices down to $6 per million British thermal unit (Mmbtu).
The world market is currently oversupplied with LNG, added Jeffers.
Russia, the United States and Iran remain the best option for natural gas. Iranians, however, are of lesser significance as they face U.S.-led sanctions.
LNG from Qatar, according to Jeffers, will be a major counter balance to future North American LNG exports as it races to increase its export capability by firstly debottlenecking and thereafter new build LNG export trains. Its gas exploitation costs are not known but industry estimates it at less than $1/Mmbtu from the ground, slightly lower than U.S. gas production cost and it is closer to the end users in Asia.
Qatar has committed to a 30 percent increase in new gas production through bottlenecking and additional trains from the huge North Field, the 1,800 trillion cubic feet reservoir of which it shares with Iran’s South Pars.
Jeffers did not want to be drawn into a debate on possible Qatar-Iran collaboration in North Field-South Pars joint production, but acknowledges the potential synergy such an alliance may have.
In principle, that remains an option, said Dr. James M. Dorsey, a senior fellow at the S. Rajaratnam School of International Studies and the co-director of the University of Würzburg’s Institute for Fan Culture.
“Qatar is, however, likely to balance its options between the fact that its shares the world’s largest gas field with Iran, the fallout of a tougher U.S. policy towards Iran, and a need to diversify its access routes because of the Gulf crisis,” said Dorsey.
Ultimately, the market will determine competitiveness. Iran may not be dependent on Qatar to lowering the cost of its production. In that sense, the challenge will ultimately be driven by technological advancements rather than geopolitics, even if geopolitics slow the process, he pointed out.
Marginal cost for Iran LNG will be higher than brownfield expansion of LNG in Qatar, added Dr. Tilak K. Doshi, managing consultant for Asia at Muse Stancil.
Qatar is not likely to undercut the price of its own gas sales by expanding too much, Doshi said.
He also pointed out that investments from large independent oil companies (IOC) are needed to develop Iranian gas fields.
But the IOCs will be very careful about investing in Iran given President Trump’s administration decertifying Iran and the likelihood that Congress would put more sanctions on Iran, according to Doshi. source: Rogzone