Crude oil production in the Niobrara region in northeastern Colorado and eastern Wyoming has quadrupled since the start of the 2010s, and now tops 600 Mb/d. Fortunately for producers in the Niobrara’s Denver-Julesburg (D-J) Basin and Powder River Basin (PRB), midstream companies not only developed enough new pipeline takeaway capacity to transport all those incremental barrels, they overbuilt. As a result, the region — unlike the Permian and Western Canada — currently has no crude-oil pipeline constraints, something that makes the Niobrara even more attractive to producers. But part of a pipeline system now moving crude out of the D-J is being repurposed to carry NGLs instead, and with D-J and PRB crude production still rising, you’ve got to wonder, is a takeaway shortfall on the horizon? Today, we continue our series on the Rockies’ premier hydrocarbon production area and the infrastructure needed to serve it, this time focusing on crude oil.
This is the second blog in our series on Niobrara production and infrastructure. In Part 1, we said that crude production in the D-J Basin and PRB took off during the Shale Era, soaring from less than 140 Mb/d in January 2010 to a peak of nearly 500 Mb/d in April 2015. With the 2014-15 oil price crash, though, drilling activity in the D-J Basin and PRB declined and Niobrara crude production sagged — much like it did just about everywhere else in the U.S. (except the Permian). By January 2017, the play’s oil output was down 19% from its apex, at just above 400 Mb/d. Since then, though, it’s been on a tear — up to 620 Mb/d as of October (a 54% gain since the beginning of last year).
Natural gas and NGL production in the Niobrara is up too, to the point that there’s a scramble on to develop new gathering systems, gas processing plants as well as gas and NGL pipeline capacity. Optimism about continued growth in the region is driven in part by a number of exploration and production companies (E&Ps) — EOG Resources, Chesapeake Energy, Anadarko Petroleum and HighPoint Resources among them — that in recent months have been talking up their improved well productivity, their efforts to hold down or even reduce drilling and completion costs (despite inflationary pressures), and their plans for expanded drilling activity this fall and in 2019. But there’s also some angst out there among E&Ps and midstreamers alike — at least in Colorado, where voters will decide next Tuesday (November 6) whether to significantly restrict where new wells can be drilled. (Polls suggest that the vote on Proposition 112 could go either way.) Even if Prop 112 were to be approved, it wouldn’t stop drilling activity in its tracks (producers have built up a big backlog of permitted well sites), but still, isn’t the oil and gas business already uncertain enough?
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