With West Texas Intermediate prices showing notable strength in the wake of the recent OPEC agreement, and a torrent of transactions having taken place in the Permian Basin, prospects of rapidly increasing production growth in the Permian have given rise to questions as to pipeline takeaway. For now, capacity in the basin is adequate— but how long will that last?

Of course, the pace of drilling and production growth in the Permian will be influenced by the price of crude. Should it falter, drilling activity may well slacken. However, a deceleration in the production ramp is likely to be measured due to hedging and, importantly, the need to speedily develop recently acquired assets in light of the sometimes generous prices paid for acreage.

Wells Fargo Securities calculated an average acreage price of about $30,500 in Permian transactions totaling $17.5 billion from mid-June to mid-November of last year.

“In most cases,” said a joint report by Wells Fargo’s midstream, upstream and refining analysts, “the substantial acreage prices paid by acquirers incentivize early and rapid development, which provides further support to our assumption of strong growth in the near term.”

Wells Fargo is one of several firms that have recently revised higher forecasts of Permian production. From an estimated 2 million barrels per day (MMbbl/d) in 2016, Wells Fargo sees output now reaching 3.4 MMbbl/d in 2020, as production grows by roughly 425,000 bbl/d at strip prices this year. Its prior high case scenario was to reach 2.8 MMbbl/d in 2020.

Assuming $60/bbl oil, J.P. Morgan sees Permian production growing by 245,000 bbl/d and 370,000 bbl/d, respectively, in 2017 and 2018. Like Wells Fargo, Tudor, Pickering, Holt & Co. has a production forecast of 3.4 MMbbl/d in 2020. Simmons & Co. predicts production growing faster, expecting output to reach 3.4 MMbbl/ d as soon as year-end 2018, and to rise further to 4.1 MMbbl/d by year-end 2019.

Simmons said it expects “takeaway constraints to become a front-line concern” for Permian producers in 2017, although “the more acute takeaway constraints” are anticipated in 2018. Similarly, Wells Fargo expects takeaway capacity out of the basin to “become tight by late-2017/early-2018,” with tightness evident in the fourth quarter of 2017 vs. in early 2020 in its prior high case scenario.

The other variable in the equation, of course, is the pace of growth in takeaway capacity.

Wells Fargo calculates existing takeaway capacity out of the Permian at 2.65 MMbbl/d, comprised of 2.45 MMbbl/d of pipeline takeaway and roughly 200,000 bbl/d of local refining demand. In addition, Enterprise Products Partners’ Midland to Sealy Pipeline is scheduled to be brought into service in mid- 2018, adding 300,000 bbl/d and bringing visible takeaway capacity to 2.95 MMbbl/d.

Projects to expand pipeline capacity that can be done quickly and easily (e.g. using pumps) could add a further 500,000 bbl/d of capacity, according to Wells Fargo. The project list comprises: Permian Express II, Bridgetex Expansion, Lone Star Crude Conversion and Midland to Sealy Pipeline Expansion (raising its capacity to 450,000 bbl/d from the currently planned 300,000 bbl/d).

The lead-time required to complete these low-cost expansions is understood to be less than one year, and “if all of this expansion potential is constructed, we peg total potential takeaway capacity out of the Permian at roughly 3.45 MMbbl/d by the 2019 timeframe,” said Wells Fargo.

The end game, of course, is to try to balance both sides of the equation, with midstream plans for new pipeline capacity keeping somewhat ahead of the ramp in production. If capacity additions lag, and the utilization rates of pipelines approach capacity limits, then the risk is that basis differentials widen—and possibly markedly as bottlenecks choke back production trying to exit the basin.

Even with the planned and potential expansions outlined above, Wells Fargo projects utilization rates exceeding 90% in 2018-2019, signaling the need for newbuild pipelines to the tune of 300,000 bbl/d for in-service by 2019. This implies new project announcements by mid-2017, assuming a lead-time of 18 months.

Will projects of sufficient size emerge in time?

The best clue probably lies in the basis differentials, which historically widen when pipeline utilization exceeds 85%. Some E&Ps have already begun layering in basis hedges.