TETCO pipeline constraint could seriously impact Appalachian gas fundamentals
In view of recent pipeline restrictions, Appalachian natural gas prices could really deteriorate later this summer as cooling loads diminish in the power sector. Most gas export routes from the region are near full utilization and storage is likely to fill rapidly as summer ends.
In response to the US Pipeline and Hazardous Materials Safety Administration (PHMSA) decision to suspend a key renewal, Texas Eastern Transmission (TETCO) reinstated a 20% reduction in the operating pressure of its gas Lines 10 and 15 between the Kosciusko (Mississippi) and Uniontown (Pennsylvania) compressor stations effective 1 June 2021. The approximate capacity impact from the pressure restriction is about 0.7 Bcf/d. The affected stretch of pipe is part of TETCO's 30-inch system (eastern leg), which facilitates up to 1.8 Bcf/d of southbound flow from Appalachia to the Southern Corridor and onward to other downstream markets in the Gulf Coast region. PHSMA suspended the renewal of TETCO's temporary request to keep full operating pressure on these pipeline segments following remedial work related to the 4 May 2020 explosion near Owingsville, KY. Enbridge, TETCO's operator, provided a notice on 10 June stating the affected lines were expected to return to full service, at the earliest, by late Q3 2021.
Southbound utilization on TETCO's 30" system had been running extremely high prior to the pressure reduction, with flows approaching 1.75 Bcf/d in May. Since 1 June TETCO volumes entering the Southern Corridor region have dropped to only 1.1 Bcf/d and are a key reason why Appalachian flows in that direction are down by nearly 0.9 Bcf/d. Aggregate Appalachian outflows, however, are trending virtually in line with May levels at 25.6 Bcf/d, as incremental volumes have moved to the Midwest, New York/New Jersey and Atlantic. Gas-fired generation in the latter two regions has been running substantially higher month over month (0.6 Bcf/d in NY/NJ and 0.4 Bcf/d in Atlantic, respectively), allowing production to be absorbed locally and offsetting the impact of seasonally declining residential/commercial loads.
The long-term reduction in southbound TETCO capacity can spell tough days ahead for Appalachian pricing, especially after cooling demand falls off from its anticipated peaks in July/August into September and October. IHS Markit had projected that Northeast storage would be 81% full at end-October even before this outage and with production averaging just 33.2 Bcf/d this summer. The TETCO outage has barely had any production impact so far; in fact, our modeled dry gas production suggests Northeast supply is averaging 34.9 Bcf/d through 24 June, which is 0.8 Bcf/d above estimated May levels.
If the 0.7 Bcf/d reduction in TETCO southbound flow were to be fully redirected to Northeast storage, everything else held constant, including production eventually declining to reflect reduced drilling activity and exhaustion of drilled-but-uncomplete wells in the region, Northeast inventories can surpass 950 Bcf by end-September. This will put strong downward pressure on pricing. Incremental opportunities to flow extra gas to the Midwest might also be hard to come by, as flows are already averaging 6.3 Bcf/d, virtually in line with the monthly record set in October 2020, and Midwest Storage Region inventories were just 12 Bcf below the five-year average as of 18 June.
Some reshuffling of production and interconnect deliveries may allow more supplies to head towards Gulf Coast LNG facilities on Tennessee Gas Pipeline (TGP), Columbia Gulf Transmission (CGT), ANR and Trunkline, but those routes are already heavily utilized, and the incremental relief will be small. Only a major downshift in Appalachian production or a significant ramp in regional demand will prevent an even more painful widening in Appalachian basis discounts later this summer.
Posted 30 June 2021 by:
Nikolay Filchev, Director
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