Natural Gas Economics – Do Futures Support Drilling?

Despite end-of-summer gas storage near record highs, gas production remains well below pre-pandemic peaks. While production has fallen, natural gas demand has mostly recovered with LNG exports ramping up. This leaves the natural gas market in a precarious position heading into winter. As a result, the natural gas forward curve is now averaging over $3.00/MMBtu for 2021. With natural gas prices on the rise and oil breaking back below $40, the question is what natural gas plays have the economics come to the rescue? Today’s energy market insight will explore the less obvious plays that could begin to see a recovery in 2021 given a strong enough rise in natural gas pricing.

The chart above shows rig activity for Green-River Overthrust, Piceance, the Barnett, and the Fayetteville, indexed to January 2013 compared to average 12-month Henry Hub strip prices. The chart highlights that when strip pricing was at or above the $3.00/MMBtu mark, producers in the GRO and Piceance were able to add rigs and stabilize activity in these non-core gas plays. To a lesser extent, the Barnett also added some rigs as well. This suggests these plays have breakeven economics in this range.  Furthermore, breaking down these plays into quartiles based on 30-day average gas IP rates for wells turned to sale since 2017, and running drilling and completion (D&C) cost sensitivities supports the conclusion that $3 natural gas prices could begin to drive reinvestment in the areas.

The table above shows indicative half-cycle breakevens for the Barnett, Green River, and Piceance. The table above also provides sensitivities to those estimates at varying capital costs and well productivity. Top tier development in every play has shown breakeven prices below $3.00/MMBtu. However, as well as costs rise and productivity falls the breakeven point can rise quite rapidly in each play, impairing the economics of a development program. These breakeven prices do not include other expenses like G&A but provide a baseline for determining additional rig activity in these plays depending on the outcome of winter on end-of-winter storage levels and 2021 natural gas pricing.  

For a more detailed analysis of BTU Analytics’ end-of-winter storage scenarios, Henry Hub prices, and the impact to US producers request a copy of our latest Upstream Outlook report.  

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Erika Coombs is Manager of Consulting Services at BTU Analytics. She leads the team to deliver customized energy-market analysis and provides BTU Analytics’ customers with critical information for a variety of energy markets including oil, gas, and NGLs from wellhead to downstream markets. She also leads research on upstream analysis, crude oil midstream infrastructure, breakeven economics, and commodity pricing dynamics for several BTU Analytics’ reports. She holds a M.S. in Mineral and Energy Economics from the Colorado School of Mines.

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