After a two-year reprieve from a nearly decade-long period of severe pipeline constraints and debilitating prices, Northeast natural gas producers are again headed for a constraint-driven market in the next five years. Appalachian supply prices last year weakened relative to national benchmark Henry Hub, reversing the gains of the past few years, and fell to historic lows as oversupply conditions prevailed and at times strained available takeaway capacity. All that despite the rig count hitting a four-year low and shale producers’ best — even unprecedented — efforts to respond to low prices with short-term production cutbacks during the shoulder seasons. So what happens when rig counts and production recover in the coming years? How long before pipeline constraints worsen and what are the prospects for new pipeline development? Today, we begin a blog series detailing recent supply-demand trends in the region and our outlook for 2021 and beyond.
As anomalous as 2020 was, it nevertheless serves as something of a bellwether for what’s to come for the Northeast gas market, so we kick off the blog series today with a review of major supply-demand trends from the past year.
On the supply side of the equation, it’s no surprise that production volumes faced numerous headwinds and were more price-sensitive on a short-term basis than ever in the region. Production was already challenged by a lower rig count heading into 2020. The Marcellus/Utica shale plays started the year with ~50 rigs, 23 fewer than in January 2019, and the rig count fell from there to a low of just 30 rigs by September — the lowest we’ve seen for the Appalachian producing region going back to at least early 2011. (We wrote in depth about Northeast gas producers’ spending cuts and drilling slowdown in Shelter from the Storm.)
Well before the rig count bottomed out, though, it became clear that laying down rigs and slowing completions would not be enough, given the cascading effect of the relatively mild winter of 2019-20 and the pandemic on domestic demand, LNG exports, and ultimately storage and prices. (As we know from previous down cycles in the shale era, changes in rig count and drilling activity can take six months to a year to translate into lower production volumes.) The Northeast region exited winter with a surplus in storage and sub-$2/MMBtu cash prices at Appalachia’s benchmark supply hub Dominion South. Facing potentially months of uncertainty around the pandemic’s impact on domestic demand and LNG exports, Marcellus/Utica producers responded with a more drastic, short-term measure: shutting in already-producing wells. As we discussed in Flick of the Switch, economic shut-ins were commonplace four decades ago, before gas was decontrolled. But since gaining the right to control and market their production in the 1980s, producers largely deemed the practice counterproductive to their economics and avoided it like the plague, at least on a detectable scale — that is, until last year.
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