“DUCs Down” Has Made Shale’s Post-COVID Bed Softer…so Far

By Mark Finley

US shale producers dramatically cut investment when oil prices collapsed last year, and – under pressure from investors – have remained exceptionally disciplined even with oil prices now above pre-COVID levels.  

The number of rigs working and wells being drilled remain well below pre-COVID levels – Baker Hughes BHI reports that oil-focused rigs in the US are still more than 40% below their pre-COVID peak.  

Moreover, current levels of rigs and wells drilled are well below levels needed to sustain current production.

And yet:  production has been sustained.  Official data from the Energy Department’s analytic arm, the Energy Information Administration (EIA) shows that shale production in June (the most recent month available) was about 7.9 million b/d.  While that is well below the pre-COVID level of 9.2 Mb/d, output has been broadly stable since July 2020 (with a brief drop during the February deep freeze).  In fact, less reliable weekly data suggests that US oil production may have begun to edge higher in July.  Holding output flat over the past year is an especially significant achievement because, as we all know, shale wells have very high decline rates:  EIA estimates that in June the “legacy production change” for US shale production was a decline of over 430,000 b/d—that is how much new production is needed every month just to hold overall supply steady.

A (shrinking) flock of DUCs

So what’s been the secret for US producers?  They’ve been feathering their beds with “DUCs down”—that is, by drawing down their large inventory of drilled-but-uncompleted wells, known by industry short-hand as DUCs.  (For those unfamiliar with the concept, a brief explanatory note can be found here.)  

The EIA’s latest monthly Drilling Productivity Report (DPR) shows that there are just over 4,400 DUCs in oil-focused plays[1] – but DUCs have fallen by nearly 2,400 (-35%) since peaking last June.  This makes perfect sense:  Under pressure to control spending, drilled-but-uncompleted wells represent a “quick fix”, allowing a company to bring new production to the market rapidly and at less cost.

Over that same period, the DPR also shows that about 5,700 wells have been completed in the oil-focused plays, while only 3,300 wells have been drilled in those formations, with the decline in DUCs accounting for the difference.  In other words, wells that have been completed over the past year outnumber those drilled by 72%!  

Yet even with a large decline in the number of DUCs, the ratio of DUCs-to-wells-drilled remains much higher than the historical average, because drilling has fallen off even more rapidly.

I should note that the EIA’s estimates of DUCs is controversial in the industry.  Many analysts feel the DUC numbers are significantly overstated.  However, there is no doubt that the industry’s DUCs inventory, however we estimate it, has fallen sharply.

And that decline should give US supply optimists pause.  US producers’ beds could get much less comfortable if they run out of “DUCs down”.

Why do DUCs exist?

First, we need a brief detour.

Why would anybody spend millions of dollars to drill a well but not bring it into completion?  Some analysts argue that producers delay completion in anticipation that oil prices might rise in the future.  Others argue that wells can be drilled to meet the terms of the company’s land lease while avoiding the significant additional expense of completing the well (which includes the hydraulic fracturing process). 

But personally, I’ve always viewed the DUCs as more of the industry’s working inventory—given the need for separate crews & equipment to drill and complete wells, there will always be gaps between the two processes.  In this view, the DUCs inventory should rise and fall with drilling activity.  However, technological advances like pad drilling and mobile rigs (which allow a single rig to drill multiple wells before moving on to the completion process) have provided a structural boost to the DUCs-to-wells-drilled ratio.

And that’s what the historical data broadly shows.  While the number of oil-focused rigs rises and falls sharply in response to oil price movements, the DUCs inventory has generally increased over time, albeit with notable declines after the 2015 oil price collapse and over the past year.  The post-COVID “DUCs down” is by far the largest in the historical EIA data set.

But now the industry is getting back to work.  The oil-focused rig count in the EIA dataset has more than doubled since bottoming out last summer, even as their DUCs count continues to fall.  

How far can DUCs fall?

So how does the DUC inventory look?  Is there more inventory to reduce?  

Partly it’s a matter of geography.  While drilling activity remains well below pre-COVID levels everywhere, the recovery has been focused on the Permian Basin, the workhorse of the US shale patch, supplying about 60% of total US shale oil production.  EIA data shows that the number of wells drilled in the Permian in June was 43% below the pre-COVID rate; in the other oil-focused basins drilling is down between 64%-73%.  Since oil-directed drilling bottomed out last summer, the Permian has accounted for over 60% of the increase in wells drilled. 

Using the ‘working inventory’ hypothesis, if the DUCs/well-drilled ratio returns to pre-COVD levels, and the number of wells drilled continues to rise at the rates seen in recent months, the Permian and Niobrara could exhaust their buffers of surplus DUCs within a few months.  The Bakken and Eagle Ford, on the other hand, appear to have room for further “DUCs down”.

But that’s a big “if”! 

• What’s the new “normal” relationship between DUCs and wells drilled?  Will DUCs relative to drilling activity return to the pre-COVID relationship?  Will technology advances continue to drive the pre-COVID trend of increasing the ratio of DUCs-to-wells-drilled?  Or will new-found financial discipline force the industry to work with a leaner inventory of DUCs?[2]
• Additionally, what’s the new “normal” for working rigs?  Will the rig count continue to rise robustly in response to the highest crude oil prices in three years?  Or will similar pressures re: financial discipline keep the rig count in check even with relatively profitable oil prices?  It is interesting to note that, even as oil prices have hit new highs, the increase in the national rig count has slowed significantly over the past few months.

How many more rigs & wells are needed if there’s no more “DUCs down”?

If the DUC inventory were exhausted, how many more rigs would be needed to maintain current production? 

In June, EIA showed that the number of DUCs in oil-focused plays fell by 233.  At the average working rate for rigs (ie wells drilled per rig per month), these plays would have needed an additional 165 rigs (+50%) to get the same of number of “completable” wells with no change in DUCs.  (Assuming DUCs and new wells have the same production on average.)  That’s more rigs than have been added in the EIA data set since the oil-focused rig count bottomed last fall.

And remember, that’s the extra work that would be needed simply to keep production flat-ish; EIA is forecasting US onshore Lower 48 production to rise slightly over the remainder of this year, and by a further 800,000 b/d in 2022.  Meeting that projected increase would require a significant increase in wells completed and/or well productivity.  (Unfortunately, EIA does not forecast working rigs, DUCs, etc.)

Indeed, the DUCs could become a factor that slows potential US production growth going forward:  If drilling activity continues to recover, the ‘working inventory’ hypothesis suggests the DUC inventory would need to increase simply to maintain a workable DUCs-to-wells-drilled ratio.  This would slow the growth in wells completed (and brought into production) relative to the growth of wells drilled.

Bottom line:  While the actual number of DUCs is difficult to estimate, everyone agrees that the numbers have fallen significantly.  The rapid depletion of the DUCs inventory has been a key factor keeping US oil production flat over the past year.  But inventories can’t fall forever—and when the DUCs inventory is depleted, companies will need to significantly ramp up new drilling (at a time when investors are demanding discipline), or face the prospect of declining production.

Industry had better have its DUCs in a row.  (With apologies to my colleague Michael Maher…)

Mark Finley is the Fellow in Energy and Global Oil at the Baker Institute. Before joining the Baker Institute, Finley was the senior U.S. economist at BP. For 12 years, he led the production of the BP Statistical Review of World Energy, the world’s longest-running compilation of objective global energy data.

[1] The Bakken, Eagle Ford, Niobrara and Permian in the EIA report. 

[2] As an aside, the difficulty in measuring DUCs and the volatility in the DUC/wells drilled relationship greatly complicates production forecasting, and highlights the need for better publicly-available data.