Appalachian pure-play CNX Resources Corp. said Monday that it would shut-in some of its wet gas production next month in response to low prices and could ultimately defer some new wells depending on how the market recovers from the oil rout and Covid-19 pandemic.

The strategy is part of a broader seven-year plan to help the company manage through the chaos that’s been created in energy markets by the coronavirus outbreak and a price war between the Organization of the Petroleum Exporting Countries, its allies and Russia that’s left the world swimming in crude oil.

“As we sit here at the end of April, it’s hard not to think back to where we were at the end of January on our last quarterly call and consider just how much the world has changed in three short months,” CEO Nicholas Deluliis said during a conference call with analysts.

As rigs and crews drop in the oil patch, associated gas production is expected to eventually decline. But the oil glut and lack of demand caused by the pandemic has had severe impacts on other commodities, like condensate and natural gas liquids. The value of Appalachian condensate fell below zero earlier this month before bouncing back. The oil storage overhang and questions about energy demand are “huge wildcards” that have found CNX trying to keep its plans for the future as flexible as possible, said COO Chad Griffith.

“To us, the biggest question is how much oil will be shut-in as we work our way out of the crisis,” he said. If oil and associated gas continue to flow through the summer, then low gas prices are expected until winter, but if oil wells are shut-in faster, then gas prices could see a more immediate lift as associated gas output declines, Griffith said. For now, the company is “assuming rock bottom prices” through the remainder of summer and anticipates a “modest recovery” in the fourth quarter.

Griffith added “that the current dynamics are so extreme and the price curve so steep,” that it makes sense to shut-in wet production soon and wait for better prices, especially considering that those wells have higher operating costs.

“We do not currently have any wells shut-in today due to economic reasons,” Griffith said. “That is something we are still assessing. We look at commodity prices every day, and we are looking at the exact right way to optimize that. We do assume that we will be curtailing a certain amount of our wet production, probably beginning in May” and lasting two or three months.

As a result, the company has cut its 2020 production guidance to 490-530 Bcfe from the previous level of 525-555 Bcfe. Capital expenditures (capex) have also been cut for the year in what management said was primarily related to lower oilfield services costs. The company now expects to spend $830-900 million, compared to a previous range of $885-950 million.

Next year, the company said it would cut costs significantly and spend $440 million to produce 550 Bcfe. If gas prices improve, it could produce 600 Bcfe. After that, the company would pivot toward production maintenance through the duration of its seven-year plan, which continues to anticipate U.S. gas prices of under $3.00/MMBtu.

The 2022-2026 plan has a “very manageable and very modest activity pace tied to it,” Deluliis said. It would require annual capex of roughly $300 million to turn 25 wells to sales each year. The company would average 560 Bcfe of annual production.

Deluliis added that the seven-year plan is aimed at generating positive free cash flow (FCF) and continuing to deleverage the balance sheet. Over the period, the company expects to generate $3 billion of FCF. It is currently FCF positive after reporting $129 million in the first quarter.

CNX produced 134.4 Bcfe in 1Q2020, compared to 133 Bcfe in the year-ago period. Average first quarter realized prices were $2.59/Mcfe, compared to $2.97/Mcfe in 1Q2019.

The company reported a first quarter net loss of $329 million (minus $1.76/share), compared to a net loss of $87 million (minus 44 cents) in the year-ago period. The first quarter loss was primarily related to noncash impairment charges of $473 million associated with the company’s midstream unit and $62 million of charges related to its southwestern Pennsylvania coalbed methane operations.