Last year served as something of a bellwether for what’s to come for the Northeast gas market in the long term: increasing takeaway pipeline constraints and weakening gas price differentials by mid-decade. The region’s outflows surged to record highs in the fall of 2020 as production also reached fresh highs. Just a couple weeks ago, the region notched another milestone on the pipeline constraint yardstick: record outflows on some pipes and near-full utilization of southbound routes on the coldest days of winter — something we don’t normally see, as gas supply requirements in the Northeast peak with heating demand and less gas is available to flow out of the region. This time, the surge in outflows and the resulting constraints were driven more by spiking demand and gas prices downstream than by oversupply conditions at home, but the result was the same: the Northeast had by far the lowest prices in the country. This happened even as other regions recorded triple-digit, all-time high prices. Today, we examine how Appalachia outflows and takeaway capacity utilization shaped up during Winter Storm Uri.
Before last month’s Deep Freeze sent the commodity markets into a tizzy and dominated our attention, we had started this series on the Northeast gas market and its slow march toward becoming constrained, again, within the next five years. We return to that series today with Part 3, this time focusing on the Appalachian production basin’s pipeline takeaway flows and capacity utilization, including the impact of the Deep Freeze. To recap Part 1, until last year, Appalachian gas producers had enjoyed a two-year reprieve from the severe pipeline constraints and debilitating prices. The dog days were over, or at least on a hiatus. Takeaway capacity had finally caught up to, and briefly even exceeded, production growth as pipeline expansions were completed, and gas prices strengthened.
It didn’t last long though. In 2020, flows and pricing dynamics began showing signs of worsening pipeline takeaway constraints again due to a combination of resilient production volumes (short-term, economic shut-ins notwithstanding), lagging demand, and high storage levels. We sounded the alarm on the potential for a price meltdown by fall in our You’ve Got Your Troubles series last summer, and sure enough, Appalachian supply prices crashed in the fall of 2020, weakening relative to national benchmark Henry Hub (i.e. basis) and not only reversing the gains of the past few years but tumbling to a historic low of $0.28/MMBtu in the NGI daily gas price index on November 9. Moreover, that happened despite the rig count hitting a four-year low and shale producers’ best — even unprecedented — efforts to implement economic cutbacks in output during the spring and fall shoulder seasons. Ultimately, Northeast gas production last year managed to eke out year-on-year gains and even hit record highs by late 2020 (we discussed the production trend in more detail in Part 2), and it didn’t help that a mild winter had left a surplus in storage vs. previous years that lingered through injection season (April-October) and into early winter. As we illustrated in Part 1, record amounts of gas had to leave the region during the fall shoulder months, particularly in November, when curtailed production came back online but demand sagged due to unseasonably warm weather.
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