The Northeast natural gas market was supposed to have turned a new leaf. After years of pipeline takeaway constraints and constraint-driven prices, the region as of late 2018 had ample, even excess, takeaway capacity on its hands. Regional prices strengthened on both an absolute basis and relative to downstream markets, and Marcellus/Utica producers had room to grow. But bearish fundamentals have rattled the Northeast — and U.S. — market in recent months. In-region demand has lagged, even as production has set new highs. Since August, capacity reductions on Texas Eastern Transmission, a key Northeast takeaway route, have limited outflows. And, to top it off, Dominion’s Cove Point LNG went offline last month for an annual three-week-long maintenance, taking another 700 MMcf/d of demand out of the market for a time — it has since come back online, as of this past Monday. But regional prices in late September and early October were pummeled in the process, raising the question: are the Northeast’s takeaway constraints back? Today, we analyze the impacts of shoulder-season dynamics on regional storage and takeaway capacity utilization.
As weak as gas prices have been lately at the national benchmark Henry Hub, Northeast prices have been even weaker. Prices at the Dominion South hub, the benchmark for Appalachian supply, were trading 20 to 40 cents per MMBtu below Henry for most of the first seven months of 2019. But in August, that discount — or basis — plunged to minus 80 cents, and averaged about $1 in the first couple weeks of October. That’s stronger than where basis stood during the worst of the pipeline constraints in prior years, but still weaker than last year at this time, even as the Henry cash price is trading at multi-year lows.
In Part 1, we unpacked the fundamentals weighing on prices. Using IHS Markit’s PointLogic supply-demand data, we can see that on the supply side, total Northeast production this injection season to date has averaged nearly 32 Bcf/d, up almost 4 Bcf/d year-on-year. A chunk of that increase is the result of steady gains that occurred in the second half of 2018, but volumes have been climbing in recent months as well. In contrast, Northeast demand — including from the power generation, industrial and residential-commercial (res-comm) sectors, as well as from LNG feedgas deliveries — was relatively flat year-on-year for that same period, at an average of about 16 Bcf/d. Thus, the regional balance jumped to being ~16 Bcf/d long supply, up 4 Bcf/d from ~12 Bcf/d last year. As we’ve noted in previous blogs, the Northeast supply exceeded regional demand on an annual basis starting in 2015, and thus, any incremental production has to find space in either storage or on takeaway pipelines to the Midwest or Gulf Coast. What has that meant for storage inventories and pipeline utilization in this new, post-constraints era?
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