The Permian Basin is facing another year of crude oil takeaway constraints, but producers are working on ways to resolve the issues sooner through a combination of capital and ingenuity, Raymond James & Associates Inc. said Monday.

Based on Raymond James’ U.S. production-by-play model, analysts now expect output by the end of 2018 to grow 920,000 b/d, with a December production rate at 3.8 million b/d, said the analyst team led by Justin Jenkins and J.R. Weston.

“For context, Permian production grew over 700,000 b/d in 2017 to end the year at an estimated 2.9 million b/d. Beyond that robust 2018 outlook, we see the growth rate accelerating again in 2019 (boosted by our above-consensus oil price forecast for 2018) with the 2019 exit rate standing at 4.6 million b/d (up another 800,000 b/d exit to exit for 2019).”

The implications for the differential (diff) forecast may avoid a worst-case scenario, but diffs should still remain wide for a period, analysts said.

All in, analysts estimate a shortfall of Permian takeaway capacity of 60,000 b/d for the second half of 2018, growing to a “touch above” 60,000 b/d in 1Q2019. The shortfall should peak in 2Q2019 at 150,000 b/d before declining to 90,000 b/d in 3Q2019 and returning to spare capacity in 4Q2019.

Raymond James is forecasting the Midland-Brent diff to average $20/bbl in 4Q2018 and 1Q2019 before falling to $15 in 2Q2019 and 3Q2019. By the final quarter of 2019, diffs should average $10/bbl and reach parity with West Texas Intermediate (WTI)-Cushing in 2020 and beyond.

Analysts have reduced their forecast for the Brent-WTI spread to an average of $12.50/bbl from $15, and raised their WTI price forecast for 2019 to $67.50.

There is “increasing conviction that capitalism and energy industry ingenuity will help us avoid a worst case scenario differential of $40/bbl and even potentially resolve this issue sooner than we previously expected,” Jenkins and Weston said.

“In the last week or so, the differential has started to pull back — falling to $20/bbl under Brent — as investors digest oilfield service company comments around moderating drilling activity, as well as updates to some midstream projects, though it also may reflect the volatility” around pipeline volume nominations, analysts said. However, don’t expect diffs to head lower from here.

Long-haul pipelines remain the preferred takeaway solution, with the next “best” option via rail, which “came to the rescue” during the 2012 and 2014 bottlenecks. Rail costs from the Permian to Corpus Christi, TX or Houston are estimated at around $6-8/bbl, which means “clear upside” for that transport method.

Adding enough rail options, however, isn’t likely before new pipeline takeaway is readied. For trucking, the story mostly remains the same, because volumes are small and “fairly inefficient,” costing around $10-15/bbl from the Permian to downstream markets. For context, Raymond James estimated that 1,000 trucks and more drivers would be needed to ship 20,000 b/d.

Some pipeline projects could be in place sooner than expected, which would solve some issues. Raymond James expects operators are “more likely to ”tap’ the brakes rather than ”slam’ them on Permian production growth. Overall, it doesn’t seem much can slow the Permian down in the short-run given operator outlooks, drilling programs and completion schedules.”

Producers overall are “surprisingly more insulated” from wide diffs than many may expect.

About one-third of Permian producers have firm crude volumes that can be shipped on existing pipelines to “better price points like the Gulf Coast for usually less than $5/bbl,” analysts said.

In addition, about one-quarter of the producers are protected by a combination of basis hedges and/or marketing agreements. And many of the remaining producers have marketing agreements backed by firm transport.

“All things considered, we still expect the Permian operators to see an increase in average 2018 realized oil prices of $15/bbl (from $48/bbl to $63/bbl),” said analysts. “This is still solidly above most operators’ budget for capital spending and planning purposes,” in large part because of the Brent/WTI pricing gains year-to-date.

Meanwhile, CME Group said Monday it plans to offer another way to price and hedge WTI light sweet crude oil in Houston beginning in 4Q2018. The WTI Houston Crude Oil futures contract would have three physical delivery locations on Enterprise Product Partners LP’s Houston system, pending regulatory review.

Futures would be listed with and subject to the rules of the New York Mercantile Exchange, beginning with the January 2019 contract month. Participants would have the flexibility to make or take delivery of U.S. light sweet crude oil at the Enterprise Crude Houston, i.e. ECHO, terminal, Enterprise Houston Ship Channel or Genoa Junction through the new contract.

“Houston’s importance as a trading and export hub for physical crude oil from Cushing and the Permian Basin continues to evolve due to the shale oil revolution and repeal of the crude oil export ban,” said CME Group’s Peter Keavey, global head of energy. “The WTI Houston contract offers commercial customers and physical traders a way to hedge their physical price risk, enhances the transparency of U.S. crude oil prices on the water in Houston and reinforces the strength of our global benchmark WTI Cushing contract.

“We believe the network of domestic users and location close to export facilities will ensure this contract provides transparent price discovery and risk transfer in the growing Houston region.”

Enterprise has a network of 19 ship docks along the Gulf Coast and is the largest crude oil exporter in the United States. Through its network of pipelines, storage and marine terminals, the firm can handle the flow of more than 4 million b/d of crude oil.