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The US shale revolution is in the midst of a dramatic come back from its 2016 lows, posting a production gain of nearly 2 MMbbl/day since September of 2016. The ascent to an all-time weekly high of 11 MMbbl/day set during the second week of July has largely been attributed to massive gains seen in the Permian Basin. However, as more and more companies rush to get a slice of the Permian pie, shortages in takeaway capacity, frac crews, and sand has already started to push development elsewhere. Before the downturn, the "elsewhere" consisted largely of the popular and now well-developed Eagle Ford and Bakken/Threeforks plays, but since 2016, some operators have diverted attention to other areas. But where have the rigs gone?
Where are the rigs?
One of the easiest methods of tracking the flow of capital in the O&G industry is to observe where operators are adding rigs. Figure 1 presents a chart of rig count and oil price beginning in 2009 and extending until May of 2018.
(Figure 1: Source: Baker Hughes, Chart: The Author)
Unsurprisingly, as oil prices have recovered from 30 dollars a barrel so have the total number of rigs. Of the total rig count, 82% are deployed in 5 of the major oil producing shale plays. These 5 shale plays consist of the Permian, Eagle Ford, Cana-Woodford, Bakken/Threeforks, and the Niobrara. To no surprise, the Permian leads the pack, making up about 68% of the total rigs within the 5 shale plays, but if we focus the analysis to exclude the Permian basin some interesting observations can be made. Figure 2 presents a chart of the percent of total rigs less the Permian, painting a better picture of what is going on outside of West Texas. Figure 2 shows that in mid-2011, the Eagle Ford and Bakken/Threeforks accounted for over 90% of the rig count in the 4 major shale oil plays and maintained between 80-90% of the rig count until the beginning of the price collapse in 2014. During this same time, the number of rigs in the Cana-Woodford play began to slowly rise taking on a larger position of the total rig count, suggesting something interesting is going on in central Oklahoma.
(Figure 2: % Rigs less the Permian, Source: Baker Hughes, Chart: The Author)
More Rigs Leads to More Production
The evidence of operator interest in the STACK is undeniable, but things become more when the STACK is analyzed in terms of production. Figure 3 presents the impressive growth in production from the core STACK counties relative to production changes in the Bakken and Eagle Ford top 3 producing counties. Since 2015, when the rigs began to shift from the Bakken/Eagle Ford, production in the STACK has increased by around 300,000 BOE/day. This increase in production is without a doubt a function of many more wells being drilled in the STACK, but how are these wells performing relative to the Bakken and Eagle Ford wells, and does the performance justify the increased interest.
(Figure 3: Core county growth, Source: Public production data, Chart: The Author)
The most popular method of per well comparison in the O&G industry is performed by generating type curves. A type curve is simply the average production from a group of wells with similar attributes such as completion type, year of first production, location, or company. Figure 4 presents the type curves of wells brought online since 2015 in the top 3 counties for the STACK, Eagle Ford, and Bakken.
(Figure 4: Location Type Curve, Source: Public Production Data, Chart: The Author)
(Figure 5: Location Type Curve Oil, Source: Public Production Data, Chart: The Author)
(Figure 6: Location Type Curve Gas, Source: Public Production Data, Chart: The Author)
On a BOE basis, the STACK has performed well in comparison to the other two plays. However, observation of the independent oil and gas type curves, represented in figures 5 and 6, suggests that the STACK's BOE numbers are inflated by the higher gas production. Comparing the 2-year cumulative production of the average well from each play shows that in terms of oil, the average STACK well has produced 58,000 BBLs less than the Eagle Ford, and 83,000 BBLs less than the Bakken. To quantify this difference in oil production in terms of dollars, some back of the napkin math using an average oil price of 50 $/bbl and 2.9 $/mmcf was performed and the results plotted in figure 7. From figure 7, it becomes obvious that the average STACK well falls behind both the Bakken and Eagle Ford in terms of dollars generated, leading one to question why operators have continued to deploy rigs to the popular Oklahoma play.
(Figure 7: Revenue for average well, Source: RyGuyR, Chart: The Author)
The Curious case of Devon Energy.
Devon Energy (NYSE:DVN) is one of the largest independent producers in the United States operating over 23,000 wells producing a whopping 543,000 BOE/day. With operations in the Permian, Eagle Ford, Barnett, the Rockies, and the STACK, Devon Energy has plenty of options when it comes to new well placement. However, in the most recent Devon reports, the Permian and STACK plays have become Devon's primary focus.
(Devon Energy: JP Morgan Energy Conference Presentation)
From analysis in the previous section, it bewilders one to think why Devon would divert attention away from the Eagle Ford in favor of a less productive STACK position. Although this appears unclear at first, digging a little deeper provides some clarity to the situation. Figure 8 shows a plot of the Devon type curve alongside the average STACK type curve, from which the superiority of the Devon wells can be noted. In fact, at the two-year mark, the average Devon well has produced more than 70,000 BOE more than the average stack well, but how does this compare to the average Eagle Ford well?
(Figure 8: Devon well comparison, Source: Drilling info data, Chart: The Author)
Figure 8 also presents the Devon type curve pitted against the Eagle Ford type curve, and again, Devon reigns supreme. Finally, figure 9 presents the dollars generated for the average well in each play including the Devon STACK average. Figure 9 shows that the Devon wells come much closer to generating the same amount of cash as the Eagle Ford and Bakken wells. Furthermore, if the Bakken oil price differential of 5 dollars is included and if there were to be a rise in natural gas prices to 3 dollars, the average Devon STACK well would outperform the Bakken wells and be in line with the Eagle Ford wells, thus providing a meaningful reason for Devon's shift of attention.
(Figure 9: Devon Average dollars generated, Source: RyGuyR, Chart: The Author)
How much room is there to run?
In the previous sections, it was shown that the average STACK well underperforms both the average Bakken and Eagle Ford wells in terms of oil produced and cash generated. However, it was also shown that the average Devon well produces better results than the average STACK well, and even better results than the average Bakken or Eagle Ford well. This leads one to wonder what Devon is doing differently to obtain these production results and if other operators in the STACK are having similar success.
Since 2015, 80% of the wells drilled in the core STACK counties have been drilled by Devon, Newfield (NYSE:NFX), Alta Mesa (NASDAQ:AMR), Marathon (NYSE:MRO), Cimarex (NYSE:XEC), Continental (NYSE:CLR), or Chesapeake (NYSE:CHK). Figures 10 and 11 present the BOE and oil type curves for each of the companies mentioned. (The first year production data was chosen due to the lack of a substantial number of wells older than a year for some of the operators.)
(Figure 10: Operator Type Curve, Source: Drilling info data, Chart: The Author)
(Figure 11: Operator Oil Type Curve, Source: Drilling info data, Chart: The Author)
The BOE type curve provides visual evidence of 3 tiers of production results, while the oil type curve shows 2 separate tiers. At first glance of the BOE type curve, it is clear that Continental is vastly outperforming, while Alta Mesa and Chesapeake are underperforming. However, the oil type curve appears to paint a different picture with Newfield and Devon at the top and Chesapeake and Alta Mesa closer to the rest of the pack. Interestingly, Continental and Cimarex, the top two producers on a BOE/well basis, are not the top two producers on an oil production per well basis, suggesting a large variance in gas production likely driven by rock properties i.e. the location of the wells. Figure 12 presents a graph of each operator's percentage of BOE which is oil at the 12-month period and supports the idea that Cimarex and Continental's BOE results are in large part attributed to gas production. Perhaps even more interesting is the fact that Chesapeake and Alta Mesa are the leaders in percent oil production despite having the lowest 12-month production on a BOE and oil produced basis. This to me would suggest that both Chesapeake and Alta Mesa are well positioned in terms of rock quality, but may not be completing wells with the same intensity.
(Figure 12: % Oil, Source: Drilling info Data, Chart: The Author)
Expanding on the rock quality analysis, figure 13 presents a map showing each company's current operating position. At first glance, it appears that Chesapeake, Alta Mesa, and Continental all have large positions outside of the core area operated by Devon, Newfield, and Cimarex, while Marathon has various positions throughout the play. Revisiting figure 13, the rank in terms of %BOE which is oil production is as follows: Chesapeake, Alta Mesa, Newfield, Devon, Marathon, Cimarex, and Continental, which is exactly the way the companies are positioned on the map moving from NE to SW. This is a clear indication that the NE portion of the play is more oily than the SW portion, leading one to inquire why Chesapeake and Alta Mesa are not seeing the large production results other operators are seeing.
(Figure 13: Map of operator location, Source: Drilling info)
To gauge the potential of the NE section of the STACK results from the Chesapeake/Alta Mesa wells can be studied and related back to the core STACK results provided by Devon, Newfield, and Cimarex. The main challenge when it comes to determining the rock quality of the core area vs. the NE portion of the STACK is quantifying the effect of the completion design on the results of the well. In an attempt to level the playing field, production results were first filtered to only include wells that were under 6000 feet, next, production results for each operator were normalized for lateral length and the amount of sand put downhole (2 factors which are highly correlated to a wells success). Unfortunately, other completion parameters such as stage spacing, cluster spacing, the number of stages and clusters, and many other design parameters are not disclosed publicly and therefore, cannot be quantified and may influence the performance of the wells mentioned in the following analysis. Figure 14 presents a plot of the best wells under 6000 ft based on monthly peak oil production for the NE operators (Alta Mesa & Chesapeake) as well as the Core operators (Devon, Cimarex, & Newfield). By removing wells over 6000 ft long, the production results among the 5 operators are much closer than the type curves would lead one to believe.
(Figure 14: Peak Oil month, Source: Drilling info Data, Chart: The Author)
Going one step further, Figure 15 presents a plot of production normalized for the lateral length and the amount of sand used in each well. This plot shows that Alta Mesa and Chesapeake are getting the same or even more oil for every 1000 lb*ft of well drilled. This analysis would lead one to conclude that the quality of rock in the northeastern portion of Kingfisher County, up into Garfield County could be on par with that observed in the core STACK area, suggesting possible room for production growth in the future, leaving Chesapeake and Alta Mesa in a good position for growth.
(Figure 15: Normalized Peak Oil, Source: Drilling info Data, Chart: The Author)
The shift of drilling rigs away from the Eagle Ford and Bakken/Threeforks plays to the lesser known areas such as the STACK play has undoubtedly been taking place over the past two years. However, the reason for this shift appears to be less clear. Results from Devon wells in the core STACK area have shown promising results, far outpacing the STACK type curve, and even outperforming the Eagle Ford BOE type curve. However, the BOE type curve is largely influenced by the amount of gas a well produces and the STACK has proven to be much gassier than both the Bakken/Threeforks & Eagle Ford plays, thus resulting in a smaller revenue stream for the STACK wells at current prices. Looking at the top 7 STACK operators showed that Continental far outperformed on a BOE basis while Newfield and Devon had the best results in terms of oil produced. Although on the surface it appeared that Alta Mesa and Chesapeake were falling short, a more thorough analysis uncovered that once the length of the lateral and the amount of sand for the well were accounted for, the well results for these two operators were on par with that of the core STACK operators. These normalized well results provide some evidence for growth potential outside of the core area that could propel the STACK into position similar to the Bakken/Eagle Ford, but currently well results are not quite on par. Furthermore, in the current environment of rising oil prices and stagnant gas prices, the more oily Bakken/Eagle Ford plays will likely garner more attention and increasingly better economics, but in the long run, I believe the STACK will continue to produce impressive results and will remain a valuable resource in the United States shale portfolio.
Disclosure: I/we have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.
I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.