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Title : Crude Oil -- The Next Five Years -- SeekingAlpha -- May 20, 2018 -- IN PROGRESS
link : Crude Oil -- The Next Five Years -- SeekingAlpha -- May 20, 2018 -- IN PROGRESS

Crude Oil -- The Next Five Years -- SeekingAlpha -- May 20, 2018 -- IN PROGRESS

For the record, I really do not like these kinds of articles over at SeekingAlpha. I don't know why. I would "love" RBN Energy to do a similar story but something tells me there is a very, very good reason why RBN Energy does not (post such an article).

But a reader sent it to me. I read it quickly, and thought it interesting. I did have some snarky comments which I will post later.

This is a very, very long article. I'm impressed that the writer took that much time -- it must have taken a fair amount of time -- to write that article, and that post it for free (of course, he will be remunerated through "clicks").

Warning: beware of confirmation bias:

Confirmation bias, also called confirmatory bias or myside bias, is the tendency to search for, interpret, favor, and recall information in a way that confirms one's preexisting beliefs or hypotheses.

It is a type of cognitive bias and a systematic error of inductive reasoning.

People display this bias when they gather or remember information selectively, or when they interpret it in a biased way. The effect is stronger for emotionally charged issues and for deeply entrenched beliefs. Confirmation bias is a variation of the more general tendency of apophenia. 

First some definitions, and comments, some taken from the article, "Crude oil the next five years":

• backwardation describes a market where spot and near-dated futures trade above longer-dated futures [higher prices today vs lower prices tomorrow]. The term structure is downward-sloping. An upward sloping term structure is called contango. Sometimes, part of the curve trades in contango and part of it in backwardation. In an environment of low inventories, the market typically trades in backwardation, and vice-versa. 
• contango describes a commodity price curve where spot prices and near-dated futures trade below longer-dated futures [higher prices tomorrow than today]. The opposite is called backwardation, where spot prices and near-dated futures trade above longer-dated future.
• From wiki: A market is said to be in contango when the forward price of a futures contract is above the expected future spot price. Normal backwardation, which is essentially the opposite of contango, occurs when the forward price of a futures contract is below the expected future spot price. 
• So, I guess that means, in a contango situation, I have a contract to sell my grain six months from now for $5/bushel and now my financial advisor is telling me that forecasts suggest that when I take payment for my grain in six months, I will get a price higher than the spot price
• So,  I guess that means, in a normal backwardation situation, I have a contract to sell my grain six months from now for $5/bushel and now my financial advisor is telling me that forecasts suggest that when I take payment for my grain in six months, I will get a price lower than the spot price
• From Investopedia:

• Traders with access to physical oil and storage can make substantial profits in a contango market.

  Other traders may seek to profit on a storage shortage by placing a spread trade betting on the contango structure of the market to increase.

  Contango means that the spot price of oil is lower than future contracts for oil. A futures contract is a legal agreement to buy or sell a physical commodity at some point in the future. The spot market is the current cash trading price for that commodity.

  For example, assume that the spot price of oil is $60 a barrel. The future price of oil two months from now is trading around $65. This represents a contango futures term structure.

  At some point, the futures price will converge to the spot price, whether the futures price is above or below the spot price. In this situation, a trader who controls physical barrels of oil and has access to storage can easily lock in a profit.

  Going back to the example, the trader will sell a futures contract for delivery two months out at $65. By locking in that profit at the higher price, and then sitting on the physical oil for a couple of months, a trader can realize substantial gains. One futures contract of oil represents 1,000 physical barrels. On a full-size oil futures contract, that would represent a profit of around $5,000 for merely storing the oil for a couple of months.

• I have great trouble keeping these two terms straight, even though it's incredibly simple in theory. I think folks like me misunderstand the concept because we don't actually have any contracts; we are simply comparing today's price with the expected futures price, and something tells me that is not the correct way to "imagine" or "understand" the terms.

Lots of data is presented. Trying to sort through this long article to get the writer's bottom line is difficult, but let's try.

First of all, and I'm thrilled with this. The writer starts off with global inventories of oil based on "days of supply." I've always felt this is the best metric for estimating whether there is a glut or a shortage of oil -- days of supply. When you go to the linked article, pay attention to the x-axis for "days of supply": for global inventories, between 2011 and March, 2018, the range has been from 38 days to 44 days.

From that graph, the writer says "global inventories have pushed the crude oil price curve into backwardation and spot prices sharply higher. [That suggests to me that going forward, we should see an increase in global inventories.]

From the article: the sharp decline in oil inventories over the past two years led to a massive shift in time spreads. In early 2016, the Brent curve was in steep contango. Prompt month prices traded $15 below the 5-year forward. As of today, Brent is trading $15 above the 5-year forward.

That tells me the amount of oil coming to market five years from now is expected to increase significantly.

But the very next statement: The longer-dated price remained practically unchanged for the past two years. Hence, the entire move in the spot price was due to the shift in the curve, which was driven by inventory decline. Importantly, the change in the spot price does not imply that the market somehow changed its view on how much it costs to produce oil. Longer-dated prices, which are set by the marginal cost of future supply, are still below $60/bbl. This means that the market sill believes that $55 - $60/bbl gives enough incentive to producers to make the necessary investments to meet future demand. The spot price rally, thus, was simply due to the decline in inventories.

And the trend has now shifted: inventories are increasing once again (see the first graph in the linked article).

Historically:

• OPEC had large amounts of spare capacity; able to bring on-line in a matter of months -- sometime just weeks -- when a shortfall occurred, for example during the first Gulf war
• non-Opec producers have almost always produced at maximum capacity
• global major oil companies have no incentive to keep any capacity idle, unless operating costs exceed the price of oil (2008 - 2009; and again in 2014 - 2015)
• that means, that over the short to medium term (< five years), non-OPEC production follows a set path and is almost completely price-inelastic

The shale revolution:

• changed that historical picture somewhat
• producers still produce at capacity, but there is much more price elasticity

This is key to the entire argument and one I often think about:

But while shale producers can ramp up production much faster than conventional non-OPEC producers, it would still take years to compensate for large shortfalls.

Read that again:

But while shale producers can ramp up production much faster than conventional non-OPEC producers, it would still take years to compensate for large shortfalls.

And note: there is also a considerable time-lag between changes in price and changes in production; by the time US shale finally peaked in April, 2015, spot prices had been falling for almost year; by the time production bottomed in September, 2016, prices had been recovering for almost a year as well
Now the discussion shifts:

OPEC's attempt to balance the market; OPEC sits on massive amounts of spare capacity; and, this led to a period of severe underinvestment by non-OPEC producers. 

This "severe underinvestment by non-OPEC producers" is something one of my readers frequntly reminds me.

The writer then gets to the nub: how much spare capacity does OPEC currently have?

• On paper: 2.8 million bbls/day. Go to the linked article to see this discussion.
• The writer's opinion: realistically, OPEC spare capacity is closer to 1.5 million bopd

History:

• the 1990's: a decade of very, very low prices for oil. Why? OPEC's spare capacity in the early 1990s, 10 million bopd
• compare that to 2 million bopd today
• Then, see discussion how shale production plays into this.

New: peak oil supply fears have been replaced with peak oil demand concerns. Look at this: 

The outlook from a huge shift in the transportation sector away from oil makes it difficult for producers to sanction a project with a 30-year life span. These projects cost billions of dollars, some even tens of billions, and could potentially become worthless. Instead, even the major oil producers push increasingly into the shale space.

Bottom line for conventional, 30-year projects: CAPEX is drying up (has already dried up, some would argue)
And then this, "the Art Berman" argument:

This will only be felt in a few years from now. Every new project that came only over the past few years, and all projects coming on-line for the next few years, were sanctioned a long time ago - some even prior to the financial crisis. Yet, despite the massive CAPEX spending prior to 2015, the new projects coming on-line hardly make a dent. In 2017, we saw only 0.2mb/d of non-OPEC production growth ex-shale (see Exhibit 7). And there is not any improvement in sight. 2018 and 2019 will look similar, and beyond that, non-OPEC ex-shale output will outright decline.

Again, the "Art Berman" argument:

On net, we expect non-OPEC supply to grow by 0.2mb/d in this year and next; after that, growth will slow down to less than 0.1mb/d by 2020. From 2021 onwards, non-OPEC supply will begin to outright decline (see Exhibit 8). Importantly, the chances for an upside surprise to this forecast are extremely slim, regardless of how prices develop over the next 5 years, because this was all set in motion many years ago. Practically none of the large projects that are sanctioned now will come on-line before 2022. But if no new projects are sanctioned today, then non-OPEC ex-shale production risks falling off a cliff in 5 years from now.

Then there is a great discussion in response to this question: with shale oil, does it really matter that there is no investment in large conventional projects?

The fact is, shale producers have shown an astonishing ability to grow production and an even more astonishing resilience to low prices. At its peak, US oil output grew by 1.5 million b/d, almost all from shale producers.

This rapid production growth eventually led to a price collapse in 2014, from $110/bbl to as low as $30/bbl. As a result, US production growth slowed to 1mb/d in 2015 and declined by 0.4mb/d in 2016.

But with prices now at over $60/bbl in 2018, US production is again growing at around 1.2 mb/d year over year. While production growth has slightly leveled off over the past months, we believe production will accelerate to around 1.5mb/d for the remainder of the year.

The writer asks: Can US shale oil sustainably grow at the peak rate of 1.5 million b/d? One of the arguments we often hear is that shale gas producers have clearly shown that the technology allows them to scale up production at will. However, shale oil and shale gas differ in key aspects.




The writer's opinion:

We estimate that with a continued production growth of 1.5 million b/d per annum, decline rates will reach 4 million b/d by 2022. That means, in order to maintain production growth of 1.5 million b/d in 2022, drillers would have to bring 5.5 million b/d of new supply online that year - more than the entire current output.

I will finish this later.

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