Source: Enverus RADAR, December 12, 2019

Trey Cowan, Senior Analysts, Enverus Drillinginfo

 

The 2020 Henry Hub calendar strip has fallen from an average of $2.76 per mmBtu, when measured nearly one year ago, to $2.29 per mmBtu at its most recent settlement reading (December 10, 2019). This average price drop of $0.47 per mmBtu over the past 11 months for next year’s Henry Hub calendar strip will likely have an adverse impact on drilling campaigns in predominantly dry gas areas like the Appalachian Region and the Haynesville Shale.

Why? Because these lowered futures prices will result in lower realized production revenues next year and implies that while production from natural gas operators could continue to grow in 2020, albeit at a much slower pace than prior years, that their profits will likely shrink. By proxy this implies that natural gas operators’ 2020 capital budgets will likely receive less operating cash flow than 2019 estimates and thus too will shrink.

For many years now the industry has looked to the infant but growing LNG export market as the relief valve for future domestic natural gas overproduction. But the law of diminishing returns is ever present as more incremental international supply is not being absorbed by global demand at the previous fast pace that was supporting global natural gas prices. In other words, global markets for domestic natural gas are not nearly as strong now as they were a few years ago when all the plans for LNG export terminals were hatched.

There is another key fundamental factor that continues to weigh on domestic natural gas prices. This factor is associated natural gas production from oil wells. We estimate that currently about one-third of the daily marketed dry gas production mix, domestically, is from oil wells producing associated gas. At current production levels that implies +30 Bcf/day due to associated gas production. This figure could grow even with flat production going forward consider the excess amounts of natural gas being flared currently at the wellsite due primarily to takeaway constraints in places like the Bakken, Eagle Ford, and Permian.

In summary, we have seen rig counts shrink over the past year in natural gas plays like the Marcellus/Utica shale, the Haynesville shale, the Granite Wash, and along the Gulf Coast while dry gas production continues to grow. The pressure on futures contracts for natural gas prices next year is not accommodating and in fact points to lower profitability for operators’ unhedged natural gas production volumes next year. However, current indications of the industry’s economic environment for next year while slowing the rig count are not to levels depressed enough that would stop the incremental growth of natural gas production. This presents a conundrum and quagmire for natural gas players next year that likely leaves this industry in a longer-term state of flux. Thus, we do not see fundamentals for natural gas markets improving domestically to a place that would spur improved pricing. Unfortunately, for all parties involved the natural gas industry is again waiting for sustained inclement weather patterns to drive demand and improve its existing standing. That sentiment and these conditions, in our opinion, is a tough posture to hold and is not attractive to many future investors.

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