Feed Me - Uri Scrambles Gulf Coast Gas Flows, Briefly Shuts Off Texas LNG Feedgas

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.

Physical natural gas spot prices in the U.S. Midcontinent trading as high as $600/MMBtu, while Northeast prices barely flinch – that was the upside-down reality physical traders were contending with Friday in trading for the long weekend, with Winter Storm Uri bearing down on large swaths of the Lower 48 and spreading bitter-cold, icy weather from the Midwest and Northeast to Texas and the Deep South. The record-shattering, triple-digit spot prices, mostly all west of the Mississippi River, were indicative of some of the worst supply shortages the market has seen during the generally oversupplied Shale Era, or ever. But the East vs. West price divergence also marks the culmination of years of shifting gas supply and flow patterns that have redefined regional dynamics. The market will be digesting the various impacts of this still-unfolding event for days, but some of the effects and implications can be gleaned already from daily pipeline flows. In today’s blog we provide an early look at the market impacts of the polar plunge.

The natural-gas market disruptions hitting the Texas-Louisiana coast so far in 2020 — a pandemic, the collapse of the LNG export market, a rare hiccup in Permian gas production, and multiple hurricanes —threw a big wrench into market expectations. Everything had been moving along pretty smoothly since mid-2016, when the first of a series of new liquefaction trains came online at Sabine Pass LNG. As new LNG export capacity started up at Sabine Pass, Corpus Christi, Cameron, and Freeport, so did relatively steady, predictable growth in feedgas demand. Then came this crazy, unforgettable year. Still more liquefaction capacity started up, but LNG export volumes plummeted, mostly due to very weak export economics. Recently, LNG exports have been picking up and, whenever hurricanes stop pounding the Gulf Coast, the U.S. will likely finally experience the full impact of all 9.15 Bcf/d of export capacity operating at full strength, requiring nearly 10 Bcf/d of feedgas across the U.S, almost 9 Bcf/d of which is located in Texas and Louisiana. Gas flow patterns across Louisiana’s dense network of pipelines already are shifting in response to the incremental demand and are signaling increased supply competition along the Gulf Coast this winter. Today, we continue our series discussing the changing flow patterns along the U.S. Gulf Coast, this time providing an overview of the main drivers of those shifts to date, including LNG feedgas demand and Northeast inflows.