The impact that the number of drilled but not yet completed wells in the U.S. onshore may have on domestic production as prices rebound is going to be big, but just how big is a bit of a mystery, Raymond James & Associates Inc. analysts said Monday.
The problem is how states tabulate drilled but uncompleted (DUC) wells versus how exploration and production (E&P) companies compile the data. It's difficult if not impossible because of incomplete state data, biased operator statistics and arbitrary estimates, said Raymond James analysts led by J. Marshall Adkins.
It's clear that E&Ps are delaying expensive completions in this low-price environment. And it's reasonable to assume that once prices rebound, DUCs will contribute to a larger than normal rebound in domestic output.
"That said, our best guess is that rebounding oil prices in 2016 could drive U.S. oil supply roughly 200,000 b/d higher than our current U.S. production by play model is forecasting," Adkins said.
Analysts are skeptical that anyone can publish a definitive DUC number. Some are too high and some are too low.
The best guess by Raymond James "with a very low confidence level" is that DUCs will account for 100,000-300,000 b/d of 2016 U.S. production growth "over and above our current U.S. supply model. Again, the actual DUC impact upon our U.S. oil supply model could be as low as zero and as high as 400,000 b/d next year."
At issue are the way states compile DUC statistics. For instance, Texas data indicates in the Permian Basin alone there are more than 2,000 wells with drilled dates but no completion dates.
"It is a massive oversimplification (and over-estimation) to assume this is the abnormal number of DUCs," Adkins said of the Permian. "In the real world, this data is remarkably unreliable given the vast amount of duplicate well entries, incomplete definitions and vague well status descriptions found in the Texas-provided data."
He said that in Texas there is "substantial double and triple counting" for the same wells.
North Dakota typically is a better records keeper among the states of DUC data. However, its official estimate that the Bakken Shale has around 1,000 DUCs doesn't correct for a "normal" level.
Analysts instead looked at individual U.S. E&P data to obtain "relatively precise abnormal" DUC data points.
Every E&P management team "tends to think about a normal DUC backlog in starkly different manners." Some E&Ps use the traditional method that the normal backlog should equal roughly 1.5-2.5 wells per average rig run during one year's time. Other E&Ps incorporate those drilling efficiencies implemented in the past two years -- and that data proved more useful in Raymond James calculations.
The efficiency method used by some E&Ps is that the "normal" backlog of DUCs should equal wells put on production (POP) by one rig over a three-month period.
"Multiple operators tended to confirm this through their abnormal DUC backlog count and rigs running in each particular play," Adkins said.
Using this efficiency metric on a producer-by-producer basis, Raymond James analysts determined that the historical "normal" backlog tends to hover around three to nine months' worth of POPs per rig; and the current backlog is roughly equal to one year's worth of POPs per rig.
"While this will not lead to a perfect, absolute number, we sensitized our hypothetical abnormal backlog around the parameters of three to nine months of POPs per rig," Adkins said.
To estimate a hypothetical "abnormal" DUC range, analysts applied the metric of three to nine months of POPs/average rig count to three asset plays -- the Permian, Bakken and Eagle Ford Shale. They concluded that a hypothetical range for the "abnormal" backlog is 500-1,300 DUCs across the three oil basins.
"This was driven by our average rig counts for each play in 2016 (130 Permian rigs/60 Bakken rigs/80 Eagle Ford rigs) and the spud-sales estimate for each play (60 days, 45 days, and 30 days)," Adkins said.
The incremental annual production from the DUCs in 2016 over 2015 ranged from 100,000 to 300,000 b/d, with the biggest impact on output occurring in the first half of next year. That said, E&Ps need to keep all of their ducks in a row going into 2016 if prices strengthen.
"Considering the historical punishment companies receive from the market when experiencing production declines," said Adkins, "we believe operators will be incentivized to maintain flat to slightly higher production levels as they lower activity going into the year."