Regional supply outlook

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bcm

bcm

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The Appalachian basin (dry gas) has been the main source of supply growth since 2012 (Figure 2.3). The incremental contribution from the Appalachian basin more than doubled in volume in 2018 (from 20 bcm in 2017 to 43 bcm), yet its share of total shale growth decreased due to the strong rises observed in almost all shale plays. This can be explained by the crude oil price recovery in 2018, which supported US light tight oil (LTO) and associated gas production. It is particularly visible in the Eagle Ford play – where incremental shale gas production almost tripled from 8 bcm in 2017 to 22 bcm in 2018 – and in the Permian basin (from 12 bcm to 22 bcm).

A further source of growth was the strong development of the Haynesville dry shale gas formation, which was one of the main shale gas development areas in the 2000s. It peaked in 2012 and then fell to half of its peak output in 2016 due to higher drilling costs compared with less deep formations in the Appalachian basin. Recovering natural gas prices since 2016 and increased well productivity brought Haynesville back to production growth, growing by almost 45% from 47 billion cubic metres per year (bcm/y) in 2017 to 68 bcm/y in 2018.

Figure 2.3 Shale gas production growth by major basins and plays, United States, 2010–18

Source: EIA (2019a), Dry Shale Production Estimates per Play (database), www.eia.gov/naturalgas/data.php#production.

2018 saw shale gas production increase by over 100 bcm, with strong contributions from almost all major dry and associated gas plays.

The growth in production from the Appalachian basin also comes from the progressive debottlenecking of pipeline takeaway capacity, which had led to a price disconnection between local hub prices and the Henry Hub from mid-2013. This price spread narrowed in 2017 and 2018 with the development of additional export pipeline capacity.1 Pipeline capacity additions reached a high in 2018, with several projects commissioned to improve takeaway from the Appalachian basin – including new pipeline capacity in the Midwest, reversal of existing pipelines to the Gulf Coast and Southeast regions, and capacity expansions (Figure 2.4). Further additions are under construction and scheduled to start operations in 2019 and 2020, such as the Mountain Valley Pipeline (20.8 bcm/y), the Atlantic Coast Pipeline (15.6 bcm/y) and the extension of the Mountaineer Xpress Pipeline (22.9 bcm/ y).

1 However, the differential remains higher during the summer months (e.g. USD 1.5 (United States dollars) per million British thermal units lower than Henry Hub for the Leidy Hub in June 2018)

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Figure 2.4 Pipeline capacity developments from the Appalachian basin (selected projects)

Gulf Coast

Source: EIA (2019b), Pipeline Projects (database), www.eia.gov/naturalgas/pipelines/EIA-NaturalGasPipelineProjects.xlsx.

Strong takeaway capacity development enables the debottlenecking of shale gas production from the Appalachian basin.

Such an improvement in interconnection capacity is likely to spur further production increases from the Appalachian basin in the near future – according to Energy Information Administration (EIA) estimates, production for the first quarter of 2019 increased by 16% y-o-y (EIA, 2019c).

Associated production from the Permian basin, the other major contributor to US shale gas growth, is still hampered by the lack of pipeline takeaway capacity. Permian gas output is driven by LTO production, which increased by over a third in 2018 (IEA, 2019a), leading to growing associated gas oversupply and resulting in an increase in flaring and negative pricing. The number of flaring permits issued by the Railroad Commission of Texas grew from 3 708 in 2017 to 5 488 in 2018 (RRC, 2019) and the amount of gas flared in the Permian rose by about 85% in 2018, reaching 553 million cubic feet per day in the fourth quarter (Bloomberg, 2019). In March 2019 prices at the local Waha trading hub plunged to negative values, reaching USD -3.38 per million British thermal units (MBtu) as of early April (DiSavino, 2019).

Another consequence of oil and gas infrastructure bottlenecks is the build-up of drilled but uncompleted wells (DUCs).2 Figure 2.5 shows that the completion rate of drilled wells improved in the Appalachian basin from early 2016, with a net reduction of DUCs following completion of previously uncompleted wells. As a result the overall DUC count decreased by half, from above 1 000 in early 2016 to around 500 in the first quarter of 2019. By contrast, drilling activity in the Permian basin shows a widening gap between the numbers of drilled and completed wells, driving the DUC count from 1 200 to 4 000 between early 2016 and the first quarter of 2019. This lack of takeaway capacity led to negative prices in West Texas’ Waha hub in March 2019 (see Chapter 4).

2 According to the EIA definition, a DUC is a new well after the end of the drilling process, but its first completion process has not been concluded (EIA, 2016).

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Figure 2.5 Monthly drilling and completion activity, Appalachia and Permian, 2016–19

Source: EIA (2019d), Drilling Productivity Report – DUC Data (database), www.eia.gov/petroleum/drilling/xls/duc-data.xlsx.

Pipeline bottlenecks hamper the development of Permian reserves and have led to a build-up of DUCs, whereas Appalachia’s improving interconnections improved its completion rate.

This forecast expects most of the LTO growth to happen in 2019 and 2020 as per the assumptions of the latest IEA Oil 2019 market report (IEA, 2019a), enabled by the rapid completion of many of the DUCs in the Permian when oil export pipelines start operations. However, this will not translate immediately into commensurate growth of associated gas production, until the abovementioned limits on gas pipeline capacity are alleviated. The contribution of Permian to shale gas growth decelerates after 2020 as the underlying LTO production growth slows. Total US natural gas production is expected to grow at an annual average rate of 2.8% over the forecast period and to reach the 1 tcm mark by 2024 (Figure 2.6). Appalachia’s contribution keeps increasing to reach 34% of total production by 2024 (from 31% in 2018). Shale gas as a whole is expected to account for over 80% of US natural gas production by the end of the forecast period – up from a current 72%.

Figure 2.6 Natural gas production, United States, 2014–24

IEA, 2019. All rights reserved.

US production reaches 1 tcm by 2024, with Permian contribution to growth in the short term up to takeaway infrastructure limits and then slowing with falling LTO growth.

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