From one perspective, the agreement struck by OPEC's members in Vienna yesterday marks the cartel's return to the business of managing the oil market, after a two-year experiment with the free market. Viewed another way, however, it represents what Bloomberg's Liam Denning termed a "capitulation of sorts"--an admission of defeat in the price war that OPEC effectively declared in late 2014. Yet while more than a few bottles of champagne were likely consumed around the US oil patch last night, this doesn't necessarily mean a return to the way things were just a few years ago, when oil prices seemed to cycle between high and higher.
We should look carefully to assess the real results of OPEC's attempt to squeeze higher-cost producers out of the market. On that criterion it was successful: hundreds of billions of dollars in oil exploration and production projects have been canceled or deferred, mainly by Western oil companies and other non-OPEC producers. If this was the 1990s, and oil still lacked viable competition, especially in transportation, and if demand could be relied on to continue growing steadily, the strategy OPEC has just ended would have set up many years of strong and rising prices for its members.
Yet OPEC miscalculated in at least two ways. First, as many experts have noted, it correctly identified US shale producers as the new marginal suppliers to the market but failed to anticipate how quickly these companies could respond to a dramatic price cut. Having squeezed their vendors and spread best drilling practices at warp speed, shale producers are now positioned to resume growing both output and profits as oil prices trend north of $50 per barrel--undermining the effect of OPEC's cuts as they go.
Its other miscalculation was in the capacity of the cartel's members--even some of the strongest--to endure the austerity that protracted low prices would bring. Although many of these countries have among the world's lowest-cost oil reserves to find and produce, it turned out that their effective cost structures, including transfers to their national budgets, were really no lower than those of the Western oil majors that have also struggled for the last two years.
A great deal of attention will now be focused on how OPEC implements its output cuts, and whether its non-OPEC partners like Russia live up to their end of the bargain. The history of OPEC deals suggests that is only prudent. However, a new factor is at work here that adds extra uncertainty to the outcome, even if OPEC miraculously achieved 100% compliance.
OPEC's formula for sustaining comfortably high (for them) oil prices has always relied on an economic paradox: They restrain their own, low-cost production and shift the marginal source of supply--the last barrel that sets the price--to make room for non-OPEC producers with much higher costs. That allows OPEC's members to collect outsize returns on their own production, what economists call "rent".
This time, though, at least until the looming gap in supply created by all that foregone investment in deepwater platforms and oil sands facilities starts to bite, the cost of the marginal barrel from shale won't be that much higher than OPEC's marginal cost. And all of this will be playing out in the context of historically high inventories. If that's not a recipe for volatility, I don't know what is.
I'm no so sure that the suppliers that shale companies will need in order to resume growing are going to be as willing to return as some observers assume.
If some have dropped out of the business, they will regain pricing power as drilling activity increases.
Some of the biggest gainers in response to the OPEC decision were service companies, which indicates that I am not the only one who thinks that the cost reductions achieved during downturn are not necessarily sustainable.
Publisher, Atomic Insights
Linked here from bloomberg. Interesting article.
You mention the other marginal producers like oil sands and deepwater at the end there in passing but I wonder what you think the outlook is for this type of production over the long term?
North American shale/tight oil is the fastest to turn on and off, so it is certainly the most relevant to supply and demand in the near term. I suspect that oil sands can just kind of chug along although further new projects may be unlikely. But deepwater seems like it could end up the odd man out given that tight oil has a similar (though perhaps falling) cost structure but is much easier to ramp up or down. Any thoughts on this?
It seems pretty clear that drilling will recover more gradually than the pace at which it was growing pre-oil-crash. Your point about the likely parallel recovery of service company pricing power is also a fair one. However, when you look at the trends in new-well productivity per rig across all the major shale regions, its clear that cheaper services were only part of the efficiency gains in the last two years. (See: http://www.eia.gov/petroleum/drilling/pdf/dpr-full.pdf)
The industry has learned a lot about economically optimizing production and recovery in tight rock since OPEC turned on the taps after their 11/14 meeting. Some of that learning works against the leverage of the service companies, too. Longer laterals and many more frac zones mean fewer wells needed to get the same production--and thus fewer rigs, etc.
There's a lot of equipment parked in dry places, waiting to be pressed back into service, but perhaps the biggest constraint will be in human resources. How many of the folks who were laid off in the last two years will want to come back and risk it all happening again if OPEC can't hold together, or if EVs take off fast enough to put a dent in demand?
Excellent question, though I think we really have to differentiate sharply between oil sands and deepwater. The former is essentially a factory that, once built, can produce at the same output for decades, subject only to economics and takeaway capacity.
Deepwater, by contrast, has the classic oil project financial structure, with a big investment up front, to be recouped in a relatively few years of peak production before decline takes over. And if that sweet spot happens to coincide with a major price dip, your economics never really recover. As such its projects are much more sensitive to future oil price level & timing than oil sands.
Then there's shale. It doesn't just differ from these others in speed, but also in flexibility of scale. Oil sands and deepwater projects really only come in chunks denominated in billions, while shale can be done to suit a chosen budget. I see that as the biggest distinction for the next few years. How much risk will companies want to take on in big, deepwater-type projects until there's a lot more clarity about the future price trajectory? That's probably a function of resource scale. If you have a Johan Sverdrup-type super-giant reservoir that can make money (supposedly) at $25/bbl or so you'll do it.
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