The restoration of full capacity on Texas Eastern Transmission earlier this month has boosted spot-market demand for Appalachian Basin gas production, bidding up cash prices at the region's upstream hubs in a trend that continues to put Northeast winter inventory levels at risk.
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On Aug. 5, the Pipeline and Hazardous Materials Safety Administration granted authorization to Texas Eastern to restore full operating capacity along its mainline.
Since the restart, demand for Appalachian production has surged.
Over the past three weeks, regional and neighboring market demand for the basin's supply has jumped to nearly 30.8 Bcf/d – up from about 30.2 Bcf/d in July, S&P Global Platts Analytics data shows.
While total demand is up, an extended spell of hot weather in the Northeast has also kept more of Appalachia's production in-region over the past two weeks. As a result, net outbound gas transmissions from the Northeast have actually fallen recently, averaging about 13.3 Bcf/d since Aug. 10 compared with an average 13.8 Bcf/d in July.
Regardless, spot prices at Appalachia's upstream hubs have surged in response to the overall rise in demand. At the basin's benchmark location, Eastern Gas South, the cash market has averaged nearly $3.61/MMBtu since the Aug. 5 restart, up from just $2.89/MMBtu in July, S&P Global Platts data shows.
The restoration on Texas Eastern has also launched cash prices into the same range as the winter forwards, recently collapsing some locations' cash-to-winter price spreads.
Since the restart, spot gas prices at Eastern Gas South have traded at an average 2 cent premium to the location's December-January-February forward-contract average at $3.59/MMBtu.
With cash prices now at a modest premium to the winter forwards, the sell-or-store calculus for many of Appalachia's producers has shifted, making spot sales increasingly attractive.
Since early August, the Northeast gas storage deficit to the five-year average has widened as a result, growing about 6.5 Bcf, or 13%, to nearly 57 Bcf. As of Aug. 25, Northeast inventories are now estimated at 757 Bcf – far short of the region's typical pre-winter inventory level at over 1 Tcf.
The collapsed cash-to-winter spread increases the risk that storage injections will continue to lag, further widening the region's inventory deficit ahead of the winter heating season.
September will be a crucial month for Appalachia's forward curves.
If above-average temperatures continue into autumn, utilities may have no choice but to run gas-fired power to cope with higher cooling demand. The high-demand scenario would likely lead to sustained cash-market strength, potentially further widening the storage deficit.
Assuming temperatures align with seasonal norms and load decreases, utilities could regain some dispatch optionality. With spot gas prices near $4/MMBtu, gas-fired generation would likely find itself on the wrong end of the merit order, to be passed over in favor of lower-cost generation options.
In the latter scenario, Appalachia's spot gas prices would likely ease as gas demand from power generators ebbs – possibly leaving more supply available for injection to storage.
The most recent National Weather Service 30-day outlook shows a slight probability of above-normal temperatures in the upper Northeast, including New York, part of Pennsylvania, and New England. Western Pennsylvania, West Virginia, and Ohio are forecast to see seasonally normal temperatures.