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Is The Global Oil Market Too Dependent On Prospective Growth In The Permian?



Anticipated US liquids production growth accounts for almost all projected non-OPEC growth in 2018 and 2019.

Roughly 70% of US production growth will come from the Permian Basin.

This raises the risk of a “black swan” even in the global oil market if productivity or production trends in the Permian unexpectedly deteriorate.

In this article, we will review the latest Drilling Productivity Report (DPR) from the U.S. Energy Information Administration (EIA) for the period covering March 2018. In particular, we will focus on the metrics and trends for the premier shale basin in the U.S., the Permian located in West Texas and Eastern New Mexico, and what this may mean for the US Exploration and Production sector (XOP).

Productivity and production trends in the Permian are crucial in any analysis of not only U.S. production trends and forecasts but also as it pertains to the global supply outlook. As we can see from the chart below taken from the EIA’s Short-Term Energy Outlook publication, production growth from North America will essentially account for almost all of the expected growth in global oil supply in 2018 and 2019.

The IEA is estimating production growth of around 0.3mn bpd in Canada in 2018 and a smaller production increase in 2019, while Mexican output is expected to remain flat. As such, the U.S. is expected to account for almost 90% of incremental North American supply growth and probably around 80% of global incremental liquids supply growth.

In turn, around 70% of the expected incremental liquids supply growth will come from the Permian basin, at least based on current trends. According to the March DPR report, production in the Permian is increasing at roughly 80,000 bpd, or 67% of total production growth in all of the shale basins* covered in this report.

*The DPR report only covers the various shale basins and so production from legacy conventional (outside of the shale basins), Alaska and the Gulf of Mexico is excluded. However, production from these three sources will remain flat at best, and more than likely decline over the next few years on a net basis, which means we can simply work of the DPR numbers as presented in the table below to get a fairly accurate picture of which basins will account for what proportion of incremental supply growth going forward

So, in essence, the entire global oil market and anticipated supply balance really hinges on what is happening in the Permian. So, let’s take a closer look at the Permian and some of the statistics and trends as provided by the EIA in its monthly DPR report.

As we can see, productivity in the Permian, although higher than a year ago, is still below its best level recorded in early 2016. Given the sharp rise in drilled but uncompleted (partly explained by logistical bottlenecks) wells or DUCs over the past two years, it may explain why productivity has not increased materially further over the past year. If this is the case, then we would expect productivity or new well oil production per rig to increase steadily as the year unfolds.

However, turning to another metric, the monthly legacy decline reported in the basin, we can see that this metric in the Permian appears to have accelerated quite notably over the past 12 months. As we well know, shale wells have a very high initial decline rate. In many cases, the production output reported by a new well in the first month can decline by 60% in the following 12 months, before flattening out somewhat.

The annualised monthly decline rate is currently at around 2.34mn bpd or 75% of total current production. A year ago, this ratio was just 62%.

Again, we can’t be certain what is driving this dynamic at present. Perhaps it may in part be related to the sharp rise in DUCs over the past 12 months, which are now being brought online. Because most of the loss in the rate of production occurs in the first year of a shale well’s life, a higher proportion of new wells coming online relative to prior years will lead to a relative acceleration in the decline rate, or at least temporarily. Nevertheless, the increase from 75% to 62% is quite striking.

Another reason may be the fact that conventional oil production still accounts for around 1mn bpd in the Permian or roughly a third of total production. The decline rate for conventional oil is much shallower than is the case for shale oil reservoirs. So, the accelerating decline rate observed over the last year may simply be due to the fact that all new wells that are being drilled are shale wells, and as such, the overall legacy decline rate for the basin is simply converging to a decline rate more typical of the average shale well.

However, it is worth pointing out that the 75% legacy decline ratio to current oil production is still much higher than the Bakken’s legacy decline ratio, which by definition is essentially a pure play shale basin. As we can see below in the data taken from the recent EIA productivity report, the monthly annualised decline rate is roughly 720,000 bpd which equates to 59% of current production, not 75%! So, the Permian’s high decline rate relative to current production would arguably be even higher if it was a “ pure” play shale basin.

As such, we should also be open to the view that the jump in the decline rate could also be related to some of the evolving issues detailed in this recent industry paper, such as well interference (or communication in industry parlance).

In essence, if companies operating in the Permian drill their wells to close to each other, it can negatively impact the anticipated recovery rates and lead to faster-than-anticipated decline rates. The other major issue, somewhat related to well interference, is the basin’s gas to oil ratio (GOR) and associated with that, the basin’s “bubble point”. This discussion can get somewhat technical, and we would direct interested readers to the following article which provides useful additional context.

The key point to understand is that as oil is extracted from a shale well, the pressure in the reservoir it is tapping will fall, and once it falls below a certain point (the bubble point), the natural gas that was initially saturated in the oil will separate from the oil and flow to the surface as a separate product.

As the chart below shows, we can see how, over time, the ratio of gas produced to oil in the Bakken basin (the oldest of the plays) has increased. More importantly, for investors in the Permian, the Bakken is essentially a “ pure” oil play or, in other words, most of the gas produced in the Bakken is associated gas.

Some commentators often point out that there remain a fair number of legacy wells in the Permian that were drilled primarily to extract natural gas and natural gas liquids. Nevertheless, even accounting for this fact, the difference at a high-level between Permian wet gas production of 10 Bcf/day, which is 5x more than Bakken wet gas production at 2.2 Bcf/day (despite the fact that the Permian only produces 3x more oil), is still quite notable.

So, if the Permian generally exhibits a higher GOR ratio (and therefore likely lower bubble point in that the difference between the basin’s initial reservoir pressure and the bubble point is smaller when compared to the Bakken), is this a negative factor for shale companies operating in the basin?

Well, not necessarily if these assumptions are already factored into the “type curves” and economic models on which production plans and capital expenditure plans are based. Generally speaking, when it comes to the GOR issue, it appears that this factor has been accurately modeled, and even where it has not been accurately modeled, the issue does not appear negative at first glance.

As an example, the incremental gas is usually produced as an incremental by-product in addition to the initial oil estimated to be recovered from a typical reservoir. Therefore, the incremental revenues from the sale of the associated gas can even add to the total product (oil plus natural gas) revenue that is generated by a typical shale well.

Further to this point, recent presentations by one of the largest Permian producers (largest in the Midland sub-section), Pioneer Natural Resources (PXD) detail how despite higher-than-anticipated wet gas output, actual oil production has still met planned oil output estimates.

However, do the shale companies operating in the Permian have sufficient data to model accurately what happens to anticipated production in the latter years of a well’s life? As we can see in the chart below, conventional oil wells (drive mechanisms are still the same in essence or as we understand) also exhibit an accelerating GOR as partial depletion sets in. But, after a while, the reservoir enters advanced depletion when the GOR actually falls once again, but production continues to decline at a similar pace as before.