When it comes to data in oil and gas, one of the most hotly contested is the EIA’s DUC count (that is to say “Drilled, but uncompleted wells”).  Who’s excited?  Controversy over data… we haven’t had a chat on that in a long time!

The key challenge to the EIA data is that there isn’t a great way to make a choice on when to stop considering a drilled well a DUC, and instead consider it a P&A liability.  So today, we revisit that dilemma and put some logic to the problem to answer the question: Why are companies choosing to ramp up rigs when they have so many DUCs to complete? 

Let’s go back in time.  Remember January 2016?  Oil prices were in the tank, we were 16 months removed from the crash from over $100/bbl to $27/bbl and prices were languishing in the low $40s.  The horizontal rig count was to bottom by March (at 314) and companies had realized in their 2016 planning exercises and reserve work that 2014 Tier 1 rock at $100 WAS NOT the same as 2016 Tier 1 rock at $40. Let’s call January 2016 the “the point of demarcation”.

For discussion purposes, we will 0 ALL DUCs that existed prior to this point.  From 2016 on, a company was likely to only complete wells that were really good and they would leave the bad ones.  Are you with me so far?  Here’s what the data table would look like.

Between August of 2016 and June of 2017, every region EXCEPT the Permian was completing more wells than it drilled.  Obviously, the Permian was the hot spot, the economics were best in the country and the mad dash for Permian acreage was on.  Constraints in completions, constraints in people and infrastructure, and time delays to drill pads are all logic explanations for this.  Between that time period (with thanks to PrimaryVision’s frac spread count), frac spreads working in the U.S. increased from 156 at the low to 338 by June of 2017, an increase of more than 100%.

In spite of the growing DUC inventory after July of 2016, companies grew the rig count from 125 working rigs to 325 by June 2017, while only increasing the capacity of “completions per month” from 314 to 450.  A tripling of rigs, offset by only 50% increase in completions capability should have caused the industry to pause and reflect.

Nope.  From November of 2017 to November of 2018, the Permian rig count grew from 335 to 441 and barely able to complete 511 wells a month, the net, post 2016 DUC counted increased to 1,766.  Put in context, that’s $7 billion of stranded capital with $10 billion of “obligations” to complete those wells and turn them to cash flow.  Here’s the data from June of 2017 to September of 2019.

The good news?  By September 2019, Appalachia had worked off 570 DUCs, the Niobrara 374 and the Bakken, Eagle Ford and Haynesville all remained flat.  The bad news?  Where all the capital was being spent: the Permian  TRIPLED it’s DUC count to 2,328.  Incredible, right?

Which brings us back to today and the question I ask myself every Friday?  Why are companies increasing rigs in the Permian???  Since September of 2019, there remain the same number of DUCs.

At 155 completions a month, there is 15.5 months of inventory to complete.  Bad for oil and natural gas prices, the data would seem to imply that companies are planning to gear up completions substantially in 2021 (historically, the DUCs data shows an inventory of around 7 months of total DUCs (inventory divided by completion pace).  In short, that implies a doubling of frac spreads in the Permian next year and all that production growth coming with it.

The point?  There is a tremendous amount of drilled, but uncompleted opportunities to bolster cash flow and drilling serves NO LOGICAL PURPOSE for many of the companies operating in the basin.  I thought 2020 was a year of growth.  It appears we are set for more of the same.