The Delaware Basin is one of the most active shale basins in the US Lower 48. As compared to its’ cousin, the Midland Basin, the play is deeper and higher pressure. These two components typically drive well costs higher. In this insight I will delve into the cost drivers and trends in the basin.
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Why the Delaware Basin? Well, frankly it is because the data is accessible. Through severance tax reduction programs in the state of Texas for wells that are classified as gas, we can back-calculate the total well costs. We also have easily accessible data for lateral lengths through the state, and completion information from Frac Focus.
But the Delaware is oil you say? Luckily a large portion of the wells in the basin are classified as gas condensate despite the high liquids volumes. My data has the current reported count of Wolfcamp wells with data at 1441. That should be sufficient to track general trends and drivers.
Figure 1: Delaware Basin Wells with Capex Data
If you are familiar with the play, you’ll notice that this is pretty decent coverage across the relevant counties, at least for Texas.
Figure 2: Operator Coverage – Delaware Wolfcamp
Cimarex makes sense, given the long-standing position in Culberson county, which is more or less all Gas Condensate. Anadarko, now Occidental, has been in the play for years. The rest of the names are expected. I have kept the original operators (outside of BPX) mostly intact so as to track operator performance.
For this analysis, I am basing the data on First Date of Production.
Figure 3: Annual Coverage – Delaware Wolfcamp
Generally, the well count tracks the overall trend of activity. I was actually surprised to see some 2020 wells in the list.
Figure 4: County Coverage – Delaware Wolfcamp
This tracks closely with the general distribution of well locations in the play.
Before digging into the capex data, we will look at the various trends in completion.
Figure 5: Lateral Length Trends – Delaware Wolfcamp
Operators have been increasing lateral lengths annually, with the median in 2019 over 8,000 feet. This is more than double that from a decade ago and operators are now routinely above 2-miles.
Figure 6: Completion Design Trends – Delaware Wolfcamp
While lateral lengths have been growing, it does seem that we have reached the limit of proppant/fluid loading. If I use post-2016, I should be able to get consistent benchmarking.
Figure 7: Average Capital Expenditures – Delaware Wolfcamp
From a total capex perspective, we bottomed out in 2016 when the industry was going through a similar price rout to today. However, we know that lateral lengths have been increasing.
Figure 8: Average Capital Expenditures Per Ft – Delaware Wolfcamp
Capex on a per-ft perspective has been steadily declining. What is driving this?
Lateral Length vs Per Ft Capex
We know that completion designs have been relatively static since 2017, so let’s look at it by year and 1000 ft lateral length bins.
Figure 9: Lateral Length vs Capex Per Ft – Delaware Wolfcamp
Not bad actually. Good to see that 2019 occupies the bottom of the curve. However, we also want to make sure that the well sample is representing a similar depth, as higher depths usually correlate with higher well costs.
As you can see, the depths are similar, so it does appear that operators were managing to reduce costs.
In essence, though it does appear that costs are slightly lower, the real driver in per-ft savings is just longer lateral lengths, which is a common thread observed in the Haynesville article, to the tune of 30% reduction by going from 5,000 to 10,000 ft.
County Level Trend
The other thing I want to look at is per-ft Capex as compared to lateral length on a County-Level basis. Once again, I will be using post-2016 wells.
Figure 10: Lateral Length vs Capex Per Ft By County – Delaware Wolfcamp
There doesn’t seem like much here as far as insights. At shorter lateral lengths there may be some disparity, but not sure it is statistically significant.
We can usually compare Capex per FT vs total proppant loading to see how much larger frac jobs are driving costs, but most of the jobs the last few years have been larger fracs so it does not really yield statistically significant insights.
I will include some operator benchmarking, but I will caveat that I don’t have 100% coverage of the play as I only have data from gas/gas condensate wells. Regardless, with enough of a well sample, some trends will emerge.
Figure 11: Operator Comparison – Delaware Wolfcamp
I used a cutoff of at least 40 wells drilled since 2017, so only a few operators emerge. We see BPX looking like pretty high cost, but they were also drilling the shortest laterals. Dirty little secret: Shorter Laterals have higher EUR’s Per Ft, which I will address in another post. So basically, not as bad for BPX as you think. Still, they still have higher costs than the closest operator from a well design standpoint.
Annoyingly, the rich get richer as EOG occupies the lowest bound of the graph. From several sources, these guys are the most aggressive at getting after their suppliers, so probably some of that in here. They are also recognized as the cream of the crop in shale land, so can probably afford to higher the best of the best.
Costs have been declining in the Delaware Basin, at least on a per-ft basis. I am generally interested to see how this trends in 2020 with oil prices declining and service companies defaulting left and right. However, that is not a sustainable business model. Service companies need to claw back some of this revenue to ensure a sustainable industry.
Let me know what you think of my analysis in the comments!