The Northeast natural gas market in recent years has been defined by its lack of sufficient infrastructure for growing production in the region. Pipeline takeaway capacity constraints have restricted production growth and driven Northeast prices to the lowest in the country. But could that soon change? With drilling activity slowing and 18 Bcf/d of takeaway due in-service over the next few years, is it possible the Northeast takeaway capacity will get overbuilt? Today, we continue our look at how pipeline takeaway capacity will stack up against Northeast production.
The Northeast natural gas market is already unrecognizable from just five years ago, having transformed from a demand market to a full-fledged producing region with more supply than it can store or burn (see see End of the Displacement and One Step Closer). But as we’ve noted in the RBN blogosphere, the region’s transformation is far from complete. Takeaway capacity out of the Marcellus/Utica remains constrained and prices continue to reflect constrained (discounted) pricing, which indicates the region remains out of whack. But starting in 2017, takeaway capacity additions are expected to accelerate with 24 projects scheduled to add 18 Bcf/d of takeaway capacity that will ease the constraints. And, there is substantial demand growth expected downstream from gas-fired power generators, LNG export terminals along the Gulf Coast and still more exports to Mexico. Until now the question has been, will takeaway capacity keep up with production. But with these pipeline projects coming due, the central question has shifted to the opposite: Will production keep up with the takeaway capacity?
To answer this question, we started in Part 1 of this series with an analysis of the production side of the equation and concluded that Northeast production remains relatively resilient, despite the dramatic slowdown in drilling activity across the U.S. in the past 18 months or so. While there is no doubt that production growth has slowed, Northeast producers have sustained volumes by shifting their new drilling activity to their most productive areas (“sweet spots”) and by utilizing their backlog of drilled-and-uncompleted wells (DUCs). Additionally, natural gas futures prices have also moved higher in the recent months, offering up some optimism for producers. Between these improved efficiencies and a higher prices now in the futures curve, what does production look like over the next few years? We looked at prospects for production growth under three price scenarios and determined that in a “Growth Scenario”, which assumes a $65/bbl WTI price and a $3.75/MMBtu Henry Hub gas price in 2021, we would expect total Northeast production to surge by nearly 10 Bcf/d, from just under 24 Bcf/d in 2016 to about 33 Bcf/d by 2021. In our “Cutback Scenario”, rates of returns are lower but remain supportive enough to encourage incremental drilling and push regional production up 5 Bcf/d to about 30 Bcf/d by 2021. Finally, in our “Contraction Scenario”, where prices remain depressed the rate of return would turn negative and new drilling would slow, but production would still increase by about 3 Bcf/d to just above 26 Bcf/d by 2021. So even in the bleakest of events for producers, we would expect Northeast production to grow, albeit minimally. (See Part 1 for a detailed explanation of the outlook.)
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