The inventory of drilled-and-uncompleted wells (DUCs) in the U.S. Lower 48 grew by nearly 1,900 between the months just before oil prices and rig counts collapsed and early 2016—a 50% increase in a roughly two-year period, according to new DUCs data in the Energy Information Administration’s (EIA) September Drilling Productivity Report (DPR—See the DPR DUC report here.). Since January’s peak of nearly 5,600 DUCs, producers have been working down the national inventory of DUCs, with the DPR showing the overall count closer to 5,000 as of August (2016) ––but that is still up more than 1,300 from the December EIA’s 2013 baseline. This incremental growth in the number of “dormant” wells is key to understanding and predicting how long production can remain supported or grow in a low-rig count environment. Moreover, there are regional differences in the DUCs inventory counts and trends that provide critical insights on how various market factors are impacting drilling activity. Today, we walk through the EIA DUCs data for each of the producing regions.
This is Part 2 of our “DUC, DUC, Produce” blog series. In Part 1, we defined DUCs, explained why DUCs are important, and discussed the various reasons they can accumulate, in addition to explaining the EIA’s methodology for measuring them. And by the way, we would like to thank all of our readers who suggested alternative names to this blog series, including Mighty DUCs, DUC Dynasty, If it Fracks like a DUC, DUCs in a Row, Sitting DUCs, The DUCs are Fracking, Dead DUCs, Lame DUCs, Rubber DUCy, DUCs Unlimited … the list goes on. Sorry if we missed yours.
DUCs have long been a source of great uncertainty in the market because they represent a potentially significant risk factor in supply forecasts and as a result price forecasts. Drilling activity alone does not tell you how many new wells are actually producing, and conversely DUCs can increase production even in the absence of drilling activity. So knowing how many DUCs there are and how many are likely to become producing wells are important to making more meaningful production forecasts. But at the same time, DUCs are a challenge to nail down. The process of DUC counting requires not only distinguishing drilled wells from completed wells in the new well data but also figuring out the total number of DUCs among existing and new wells drilled. The EIA uses a combination of Baker Hughes rig counts and state-level well data, among other datasets, to identify new wells drilled, but that data doesn’t necessarily tell you whether the well was completed. To do that, EIA makes assumptions about drilling and completion times to estimate when a newly drilled well will begin producing. So the first step in estimating the number of incremental DUCs is to more concretely distinguish drilled wells from completed wells.
As we discussed in Part 1, EIA does this by using a relatively new dataset—FracFocus.org’s national fracking chemical registry—to identify the completion phase, marked by the first fracking. If a well shows up on the registry, it’s considered completed and not a DUC. Wells that are not reported or that are not likely ever to be completed are excluded from the count, as are recompletions (by counting wells fracked multiple times only once). EIA then takes the difference between the drilled wells and completed wells and adds it to the prior month’s total DUCs inventory to get the current month’s total DUCs (more detail on EIA methodology in Part 1). As we touched on last time, it is normal for producers to maintain a certain baseline inventory of DUCs, regardless of market conditions. So it’s not so much the absolute number of DUCs that is relevant to our analysis, as it is the change in the DUC inventory from before crude oil prices began to erode back in 2014, because that’s the incremental number of wells that are the most likely to come into play should prices justify completion.
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