SynMax Research: Between September 29 and October 3, 2025, 18 natural gas pipeline receipt facilities across Pennsylvania and West Virginia recorded significant flow reductions totaling 1.85 BCF/d (1,847,469 MMbtu/d). The reductions were concentrated in Greene County, Pennsylvania, where 6 facilities experienced a combined loss of 0.83 BCF/d, representing 45% of the total regional decline.
Greene County emerged as the clear focal point of the flow reductions. The six affected facilities in this single Pennsylvania county included four operated by Equitrans (JUPITER, BEACON IC RUN 2, AURORA INTERCONNECT, HOPEWELL RIDGE), one by Texas Eastern Transmission (RICE ENERGY - BAMBINO), and one by Columbia Gas Transmission (Gibraltar III). Beyond Greene County, the reductions extended across eight additional counties in Pennsylvania and two in West Virginia, affecting 14 Pennsylvania facilities (1.51 BCF/d loss) and 4 West Virginia facilities (0.33 BCF/d loss).
Operator Impact
Equitrans sustained the largest aggregate impact across its system, with five facilities experiencing a combined loss of 0.71 BCF/d. This was followed by Dominion Transmission (4 facilities, 0.30 BCF/d), Texas Eastern Transmission (3 facilities, 0.26 BCF/d), and Mountain Valley Pipeline (1 facility, 0.21 BCF/d). In total, eight pipeline operators recorded flow reductions during the period.
The single largest absolute reduction occurred at Mountain Valley Pipeline's GREAT HAMMERHEAD facility in Wetzel County, West Virginia, where flows declined from 531,295 MMbtu/d to 318,265 MMbtu/d—a loss of 213,030 MMbtu/d (40.1%). Equitrans's BEACON IC RUN 2 in Greene County recorded the second-largest absolute decline at 172,739 MMbtu/d (46.4% reduction), followed by AURORA INTERCONNECT at 167,344 MMbtu/d (61.5% reduction).
Two facilities experienced near-complete shutdowns. Equitrans's JUPITER facility in Greene County ceased all flows, declining from 200,000 MMbtu/d on September 29 to zero by October 1. Dominion Transmission's MEDIX RUN M&R (LN-50) in Clearfield County similarly collapsed from 101,256 MMbtu/d to just 1,100 MMbtu/d—a 98.9% reduction.
Temporal Development
The flow reductions developed gradually over the five-day period, with the most significant initial declines recorded on September 30 and continued reductions through October 3. Most facilities stabilized at reduced flow levels by October 2-3. Of the 18 affected facilities, 6 experienced severe reductions exceeding 50%, 5 recorded moderate reductions between 25-50%, and 7 saw minor reductions below 25%.
Maintenance Activities
The flow reductions align with scheduled maintenance activities across multiple pipeline systems, with 2025 maintenance levels notably elevated compared to prior years. During the comparable September 29 - October 7 period in 2024, maintenance-affected production ranged from 0.80 to 0.85 BCF/d. This year, the same period shows 0.85 to 1.05 BCF/d affected—a significant increase.
Late September through early October represents peak maintenance season in the Northeast, with Cove Point LNG undergoing its annual maintenance beginning in late September. Equitrans posted maintenance schedules beginning around October 1, accounting for declines across its four Greene County facilities, while Tennessee Gas Pipeline and Transcontinental Gas Pipe Line similarly reported maintenance activities. The coordinated timing and phased implementation pattern across operators suggest planned maintenance events rather than operational disruptions.
Market Context
While Dominion South next-day delivery cash prices fell below $1.46/MMBtu during mid-September—approaching typical shut-in thresholds—the predominant driver of the production declines appears to be infrastructure maintenance rather than economic curtailments. Some minimal economic-related shut-ins may have occurred at select facilities, but operator-reported maintenance schedules indicate infrastructure maintenance was the primary factor behind the 1.85 BCF/d reduction.
Northeast Shut-In Economics
Overall Northeast shut-in economics suggest some potential for economic shut-ins for companies such as EQT’s pure dry gas wells and Antero’s higher liquids wells. Taking into account current NGL, crude oil, and natural prices in the Northeast along with the variable costs of flowing the wells, both EQT and Antero are near shut-in pricing economics for some of their wells based on total netback pricing.
Conclusion
Pipeline maintenance has been the dominant factor negatively impacting Northeast natural gas production for the months of September and October. There also may be economic production shut-ins impacting production, but it is probably very limited. We expect Northeast natural gas production to rebound significantly during the second half of October and into November once Cove Point LNG comes back online and Dominion South cash pricing is significantly higher. Both the Short-Term Production Forecast and the Long-Term Production Forecast are forecasting a strong rebound in Northeast natural gas production for November. The Short-Term Production Forecast is an estimate of absolute maximum productive capacity and does not take into account maintenance, economic related shut-ins, and freeze-offs. It should always be too high relative to the production pipeline scrapes.