The U.S. natural gas pipeline grid is not sufficient to handle the swift changes occurring in both supply and demand, and significant operational and commercial challenges may occur without additional midstream buildout, executives said Tuesday in New Orleans.

Market experts have said they expect liquefied natural gas (LNG) exports to reach 12 Bcf/d over the next five years, and production from the Permian Basin is estimated to reach up to 25 Bcf/d, up from the current 11 Bcf/d, during that same time frame.*

If these industry forecasts hold up, the natural gas market will likely be challenging and extremely volatile at times, according to Jonathan Ochoa, Energy Transfer’s senior director of commercial optimization and market fundamentals.

“It’ll be very interesting as more gas comes online and we continue to push the threshold in how full these pipelines are,” Ochoa said during a panel discussion at the Gulf Coast Energy Forum.

In the Permian Basin, oil-directed drilling has resulted in a rampant swelling of associated gas output that has overwhelmed existing infrastructure and caused regional prices to sink to unprecedented levels. The first in a trio of planned takeaway projects began operations in September, with the 2 Bcf/d Gulf Coast Express filling at warp speed ever since.

However, even with two other 2 Bcf/d pipelines set to begin service in the next few years, “production will likely continue to outpace demand,” Ochoa said.

Other areas along the Gulf Coast are experiencing bottlenecks as well. Enable Midstream Partners LP is aiming to alleviate the constraint in moving gas from northern Louisiana to the Gulf Coast with its proposed Gulf Run pipeline project. The pipeline, for which anchor shipper Golden Pass LNG has signed on for 1.1 Bcf/d, would provide access to gas from the Haynesville, Marcellus, Utica and Barnett shales, as well as the Midcontinent region.

Although Enable pushed back its certificate filing at the Federal Energy Regulatory Commission to early 2020 from an expected filing date later this year, the company is fully prepared to move forward even without additional customers, according to Josh Browning, director of business development. Enable can then expand the pipeline capacity to about 2.8 Bcf/d.

Browning touted Gulf Run’s accessibility to multiple supply basins as an effective tool for navigating the market as supplies change over time. “Customers don’t need a crystal ball. When dynamics change, they can change with it.”

Like Ochoa, he agreed that additional pipelines would be needed to accommodate the expected growth in Gulf Coast demand, which is projected to grow by 10 Bcf/d by 2024. Including the three Permian takeaway projects and Enable’s Gulf Run, another 5.4 Bcf/d of capacity is needed, he said.

Oklahoma City-based Enable is working to alleviate constraints in its hometown as well, as the region has failed to keep pace with rising production in the Anadarko Basin. The company’s Project Wildcat began operations during the second quarter, with Continental Resources Inc. subscribed for all 400 MMcf/d of capacity.

Meanwhile, LNG exports have quickly accelerated from zero in 2015 to around 3 Bcf/d last year. They’re projected to reach 7 Bcf/d by the end of 2019.

While Cameron and Freeport LNG recently started production at their facilities, additional trains are expected to enter service in the months ahead and some second-wave LNG projects are scheduled to begin operations in the next few years.

“That’s a lot of molecules,” Ochoa said. “It’ll be challenging when you have hurricanes, fog. There’s not enough storage at LNG facilities, and it will be challenging to push that much gas back onto the market. Storage has to be part of the equation.”

However, sub-$3 gas prices are doing very little to incentivize storage buildout, according to Tim Hermann, Southern Company Gas’s president of storage fuels. Instead, any future development likely will be customer-based and take shape in the form of expansions rather than newbuilds.

“LNG and petrochemical development in the Gulf Coast has created new markets with critical balancing needs,” Hermann said on Wednesday, the final day of the conference. “It’s hard when there is no line of sight. However, we are seeing some modest expansions taking place.”

Natural gas demand from each single LNG production unit equates to a large, northern utility, consuming around 250 Bcf/year, Hermann said. However, LNG loads are harder to predict and the tightening capacity on pipelines in the Gulf Coast will result in less operational flexibility during unforecast events. As a result, significant operational and commercial challenges may occur, including pipeline outages, liquefaction train trips and shipping disruptions.

“The whole industry is going to be learning in the next six months as these new LNG trains come online at the same time the North is getting a pull from winter weather,” he said.

*Clarification: The original story included projections cited by Energy Transfer’s Jonathan Ochoa, senior director of commercial optimization and market fundamentals, regarding the growth of Permian Basin dry gas production and liquefied natural gas (LNG) feed gas. The Permian projected dry gas production growth estimate of 17-23 Bcf/d by 2025 and the estimated LNG feed gas growth to 14 Bcf/d by 2025 are commonly cited estimates by the industry and not projections by Ochoa.