Oil Prices, LNG Demand Key to Dry Gas Producers' Fate

Copyright © 2021 Energy Intelligence Group

Things got ugly last week for producers in the top US shale gas plays, with prices plunging under $1 per million Btu at supply hubs in Appalachia and into the $1.60s in the Haynesville Shale. But industry analysts and executives are looking beyond bearish short-term fundamentals, pinning their hopes on an expected resurgence in demand and in dry gas drilling activity to meet it. Just how bullish the outlook will be in the Marcellus and Utica Shales in the Northeast and the Gulf Coast's Haynesville depends on a host of factors, including how quickly pandemic-killing demand ramps back up. But it's becoming clear that a $1 handle will be in the rear view mirror by early next year. "We're not calling for $4-$5 gas because then every basin would be flooding the market with supply," Enverus analyst Rob McBride told Energy Intelligence. He said a $3/MMBtu average in 2021, with a ceiling in the mid-$3 range, makes sense for producers to thrive again. "It doesn't need to go much higher than that." This forecast is also driven by shifts on the supply side of the market -- and not just in gas. With oil drilling activity grinding to a slow crawl, the table is set for a rapid drop in associated gas volumes, with little help to come from a $52.50 per barrel average price for West Texas Intermediate crude next year, according to Energy Intelligence's Research & Advisory unit (NGW Aug.24'20). That will set associated gas volumes falling just as demand begins to recover this winter and into next year -- inevitably increasing the call on dry gas volumes from Appalachia and the Haynesville to make up the difference. "I'd be careful especially in September and October drawing firm conclusions about [weak pricing], though it certainly is a telltale sign," McBride said. "If you are getting those really bad cash markets but you don't see the forward basis curve reacting drastically the way it did in the past, then it's saying, 'OK, this is September, our worst time of year for cash trading in those regions.'" Still, last week's freefall is evidence of a re-emerging gas glut in Appalachia outside of the winter, said McBride, co-author of a recent Enverus report on the impact a greater demand for dry gas production would have on the Marcellus/Utica and Haynesville plays as associated gas volumes fall. Just how that will impact dry gas prices moving forward is still being debated, but analysts' consensus in a recent survey by Energy Intelligence sees a nearly $3/MMBtu average Henry Hub cash price in 2021 (NGW Sep.14'20). 'Measured' Improvement Seen Dry gas producers may be eyeing future price gains and better rates of return, but they are still dealing with more immediate concerns, Goodrich Petroleum President Robert Turnham told Energy Intelligence. “Although I think you will see the rig count creep up with much better prices and exceptional returns in the Haynesville and Marcellus, with the curve backwardated beginning in 2022 and the fact that companies are focused on generating free cash flow, I believe the growth in activity will be measured," Turnham said. "The other key variables affecting future natural gas prices and activity levels will be oil prices and demand recovery on the other side of the pandemic. If oil prices are rangebound from here, activity levels in the Permian Basin will remain muted, which will obviously be bullish on gas prices," he added. "But if oil prices rise significantly you clearly will see higher activity and supply of associated gas, which could take a little off the top of the gas price curve." Appalachian production has remained relatively steady through the pandemic and is estimated at around 32.8 billion cubic feet per day, down only 1.4 Bcf/d from its 2019 high. But the play's active rig count has fallen from 46 to 26 as E&Ps leaned harder on the region's large inventory of drilled but uncompleted wells (DUCs) (NGW Aug.24'20). As of mid-August, producers had tapped 189 DUCs since Jan. 1, leaving 231 available. However, continued reliance on DUCs to maintain production could present a problem, McBride said. "The longer you wait, the harder it is to get a rig out there," he explained. "Eventually, we'll see the companies that are healthier diverge from the ones that are not. But right now everyone is keeping their cards close to their chest and not revealing exactly when they are going to deploy activity back to the field." But once those rigs and frack crews are deployed and production rises, Appalachia could face pipeline constraints as early as mid-2021, Enverus found. That would be averted if the 2 Bcf/d capacity Mountain Valley Pipeline opens as expected early next year (related). Meanwhile, the Haynesville in Northwest Louisiana and East Texas serves a much different market than the Marcellus/Utica, one driven less by seasonal demand than the Gulf Coast industrial juggernaut. It produces less than a third of the daily output in Appalachia -- roughly 11.6 Bcf/d -- but it has been more resilient, falling just 0.6 Bcf/d since last year's highs. A key reason is its catbird seat when it comes to meeting Gulf Coast LNG demand, which could rise substantially if global gas markets recover soon and Exxon Mobil-Qatar's Golden Pass LNG and Tellurian's Driftwood LNG export terminals come to fruition. Enverus estimates that Haynesville production will rise another 5 Bcf/d by 2025 to meet that demand growth, necessitating four new pipelines to accommodate those projects alone. Tellurian in particular has found it hard to sign the customers needed to underpin its 27.6 million ton per year (3.8 Bcf/d) terminal. But this could change if global demand revives and grows. Golden Pass is a bit more certain and could create 2.5 Bcf/d of additional demand for Haynesville E&Ps. Tom Haywood, Houston

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