On April 19, Freeport LNG took some in the industry by surprise with the announcement that it would delay the projected start date for its $13 billion terminal by nine months, to September 2019 for the first train launch. The second two trains are projected to begin service in 2020.

According to Platt’s, the delay is due to “a combination of flooding following Hurricane Harvey of lay-yards where equipment, including steel pipeline, was stored, as well as contractor execution delays.”

In a report published on April 30, BTU Analytics took a look at the market’s reaction to the delay, noting that “it is a very fine line between LNG being important to the natural gas market, and the market becoming dependent on new LNG demand.”

LNG has become increasingly important in the natural gas demand mix. The report noted that since April 2017, “monthly average deliveries to the Cheniere facility in Cameron Parish, Louisiana, have consistently outpaced deliveries into the heart of New York City.” This was true even during the severe cold temperatures this winter, according to the report’s author, senior energy analyst Matthew Hoza.

How to keep the significant amount of associated gas being produced in the Permian Basin moving on pipes is a significant concern for producers. A delay such as the one announced by Freeport LNG “will cause some heartburn in the overall market,” according to the report.

“With the delay of Freeport’s first three trains by nine months, we have effectively cut out 30% and 20% of new LNG capacity coming online in 2018 and 2019, respectively,” the analyst said.

To determine the effect of the delay on pricing, Hoza looked at average annual Henry Hub forward curves, before and after the announcement of the delay. The 2019 curve fell by $0.07 day-over-day.

A separate BTU Analytics report issued on May 9 zeroed in on Permian price setbacks. Senior energy analyst Jake Fells noted that “over the last few months, almost every conversation is eventually related to what’s going on in West Texas, especially with both oil and gas prices blowing out.”

Making matters worse are the growth in oil production—up 30% in March vs. the year-ago period—and gas production, which has risen by about 20%, the report noted. The basin’s rig count has hit the highest point since January 2015.

Operators are looking for a way out for their oil and gas, “primarily the Gulf Coast,” Fells said.

Natural gas production is more deeply mired in infrastructure shortfalls than oil, of course. “For gas markets specifically, until infrastructure constraints are relieved, Waha could get really weak, potentially going to zero or even negative, as the Permian story evolves from a displacement story to a physical capacity story,” Fells said.

Rising oil prices provide the ultimate carrot for producers to keep on drilling, pushing cares about natural gas pricing into the background. BTU analytics expects the pipes could reach capacity for gas, in tandem hobbling oil production takeaway, later this year. Pipeline projects that could alleviate the situation—Gulf Coast Express, among others, and the recommissioning of Old Ocean Pipeline alongside a North Texas Pipeline expansion, could bring some relief in the next 18 months, according to the report.

In April, the Midland vs. WTI basis differential was more than negative $12; the Waha vs. Henry Hub basis was about negative $1.50.

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