Benchmarking Appalachian NGLs and Midstream Infrastructure

Since we discussed NGL supply in the Permian basin last month, let’s deep dive into another key basin – the Appalachia. Covid-19 is hitting the oil and gas sector as rig counts are falling on reduced associated gas production from wet shale plays. Where does the Appalachia go?

Where we’ve been to where we are:

Appalachia has been one of the biggest shale regions, producing about 33 Bcf/d of natural gas, of which ~9 Bcf/d (or ~26%) is estimated to be wet gas. Over the last 7 years, the value of residue gas and NGL in aggregate exceeded local gas prices, incentivizing producers to develop wet acreage. As wet production increased, so did processing infrastructure. Midstream companies anticipated the wave of production and aggressively increased processing plant capacity. Processing capacity in the Appalachian currently stands at ~10 Bcf/d, while basin-level utilization stood at 80% as of 4Q 2019.

Unlike the Permian, the Appalachian gas processing landscape is highly consolidated. Six processors operate in the basin, with MarkWest dominating the gas processing landscape, operating 68% of total capacity and 69% of processed volumes in 4Q 2019. MarkWest operates an integrated network of processing and C3+ fractionation network with distributed de-ethanization for ethane flexibility. Until 2Q 2020, ethane prices at Mont Belvieu had been soft, barely staying above natural gas prices in the U.S. Gulf Coast. This therefore provided no economic incentive for Appalachian gas producers to extract ethane beyond their “must recover” levels. During 2019 and in 1Q 2020, there were extended periods where ethane frac spread in the Appalachian basin went negative, after factoring in the tariff on Enterprise ATEX ethane pipeline as a “sunk cost”. An offshoot of this market development has been the development of an informal secondary market for ATEX capacity wherein producers negotiate rates that reflect the true value of ATEX pipeline capacity. In 4Q 2019, Appalachia producers extracted 255 Mbpd of ethane, or about ~36% of total estimated ethane entrained in the gas stream. While only 2 pipelines were available for ethane takeaway in 2014 (ET’s Mariner West and EPD’s ATEX), there are now 4 pipelines with an aggregate take-away capacity of 310 Mbpd for ethane disposition to multiple markets such as Mont Belvieu; Calvert City,KY; Sarnia; and waterborne exports via Marcus Hook. Lack of pipeline take-away capacity is becoming a limiting factor as effective pipeline utilization remained high at 91% in 4Q 2019.

Propane+ (or C3+) supply in the Appalachian basin for 4Q 2019 stands at 420 Mbpd, with MarkWest fractionating ~300 Mbpd, about 71% of the basin’s C3+. Basin level C3+ capacity utilization stands at 76% for 4Q 2019, with total installed capacity of 433 Mbpd. Since 2019, the Mariner East 2 pipeline has been a game-changer for propane and butane disposition. For one, it has ensured that the basin is drained of C3+ production (esp. in the summer), limiting downside pricing exposure for producers, but it has also increased competition between domestic and international buyers for winter supply. The resultant drop in rail utilization to move propane and butane supply has not gone unnoticed. With more expansions in store on Mariner East 2, recalibration of all-in rail costs is crucial if they hope to compete with pipelines.

Where we go from here:

Drilling activity in the Appalachia has slowed due to COVID-19. Consequently, Midstream companies are also slowing expansion plans. Nevertheless, at the time of this report, there were plans for 11 new processing plants, with incremental capacity additions of ~2.5 Bcf/d. These plants have planned in-service dates ranging from 3Q 2020 through 2H 2022. Also, additional de-ethanization capacity of about 30 Mbpd and 110 Mbpd of C3+ Fractionation capacity is expected coming online by YE 2020. Upcoming additional capacity should keep major pipeline capacity constraints at bay for at least the next few years.

With the current environment presenting a significant bar for new midstream projects due to a combination of reduced drilling and PDP well shut ins, it appears that NGL midstream infrastructure in the Appalachia is now more than adequate to meet producers’ needs for some years to come.