Nurturing the green shoots of upstream growth
A combination of cuts to upstream capital spending and steepening well decline rates will threaten global supply security, industry leaders warn
As companies doubled down on cutting costs over the past two years, a leaner and more efficient upstream industry has started to emerge. That was one of the key messages from the Upstream session at
AOGC 2017 on 8 May, which saw leading industry figures chart new routes for upstream success in a panel appropriately entitled the Green Sheets of Growth.
Shaikh Nawaf al-Sabah, chief executive of
Kuwait Foreign Petroleum Expansion Company, kicked off proceedings by underscoring the sheer scale of the disinvestment seen under the low-price climate. "About $1 trillion has been removed as capex from companies' development plans," he said, noting this has had an inevitable impact on exploration success. "Last year we found one-quarter of the barrels we'd found in the previous 15 years. That's a huge drop."
Similarly, on the development side, some 4.7bn barrels of oil development projects were sanctioned last year-the lowest in 40 years, and a 30% drop from 2015.
The net effect on decline rates in oil and gas wells has been substantial. According to Shaikh Nawaf, these have doubled to 5% on an annual basis.
Meanwhile, oil demand continues to increase, even as decline rates continue to steepen. In this new paradigm, Shaikh Nawaf conceived the traditional "call on
Opec" as effectively a "call on shale". "The market is setting itself on the marginal cost of a shale barrel, and shale costs are going down with US tight oil at $50-60 per barrel. Margin call
Returns are strong. While two-thirds of all conventional producing fields are getting internal rates of return (IRRs) of below 15%, for unconventional fields, two-thirds of production is yielding IRRs of above 15%.
The question is, how much tight oil can the US produce? "If we're talking 8 or 9 million b/d, that alone won't provide the additional barrels needed by the market."
Arnaud Breuillac, president of exploration and production at
Total, spoke of a new real- ity in which disruption is shaking up the market. Volatility may be bad, he said, but it was inherent to commodities businesses.
"The industry is a victim of its own success," he said. "The success in developing unconventional resources led to the oil price fall."
In this context, less money is going into exploration. "In Asia in 2016 there was a 62% decline in licensed areas, a dramatic fall which will have a long-term impact," said Breuillac.
The challenge is how to adapt to the new reality. "The first thing to say is that since we can't control external parameters, we need to be good at what we can control-operating costs. At Total, we've been pace setters in the industry, by cutting in half our global opex from just below $10/b in 2015."
In February, Total announced it was sanctioning 10 new projects over the next 18 months, aiming at an IRR of more than 15% at $50 b/d. "We need to ensure that projects are resilient at today's prices," said Breuillac.
Mohammed Anuar, upstream chief executive at
Petronas, also flagged up the Malaysian giant's relentless focus on driving down costs. At Petronas, production costs were close to $10/b in 2014, he said. Last year, this was down to $7.30/b, and it hopes to get to $5/b next year.
"We are looking more at integrated value, to see what we as an integrated company can do to find additional margin within the interfaces between businesses," he said. "And we can see there is plenty to learn from the supply chain and procurement to reduce costs."
While depressed oil prices have put a dent in revenues, the affordability of liquefied
natural gas has improved significantly. "At $100 oil prices, LNG costs about $15 per million British thermal units. At that level, only Japan, Korea, and parts of China can afford it. Now that LNG is more in the $5-7/MMBtu range, all of a sudden the likes of Bangladesh and Thailand start opening up," said Anuar.
The current climate has opened up space for new entrants to the market. Bob Davenport, managing director Malaysia at
EnQuest Plc, a UK-listed upstream operator, highlighted how his company is creating new value from late life assets.
In January 2017,
BP announced it was selling 25% of the Magnus field to EnQuest. "The cash consideration was zero. They handed to us 25% of the asset with the promise to in future, as profit allows, to pay the sales consideration, and if the profits don't come, there's no cash to pay," said Davenport.
Why do such a thing? The answer was simple. "BP had worked out that Magnus is worth more to BP shareholders in the hands of new independents like EnQuest, because of our proven ability to extend the field life and reduce costs," said Davenport.
This article appeared in the AOGC daily newsletter, produced by Petroleum Economist for attendees of the 19th Asia Oil and Gas Conference held in Kuala Lumpar.
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