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Both Physical & Economic Forces Impact NGL Production & Recovery

1Q 2020 – The recent volatility in crude oil pricing from simultaneous supply and demand shocks has put oil plays in an unsustainable price bind. Additionally, physical constraints, such as filling crude storage at key hubs and stagnating pipelines, have begun to further pressure crude prices. Constraints are also emerging for E&P companies targeting liquids-rich gas acreage, albeit in less direct ways than running out of storage capacity. The economics of ethane recovery are not advantageous for producers in most US shale basins today, but the decision to reject ethane is not governed by economics alone. Physical limitations from infrastructure are beginning to emerge, which can impact the economics of liquids-rich production beyond what the BTU Analytics wellhead economics model might predict. While the BTU Analytics wellhead economics model assumes that producers will make choices to drill new wells or make decisions to recover or reject ethane based on pricing signals alone, the situation on the ground is more complex.

One region where liquids play a major role in the economics of gas drilling is Southwestern Appalachia, which contains both liquids-rich wet gas (herein defined as >2 GPM) and dry gas windows, meaning that all Southwestern Appalachia producers do not benefit equally from commodity price swings. Liquids pricing is typically linked to crude prices, which creates the potential for an offsetting effect for rich gas producers in times of weak natural gas pricing. Liquids uplift lowers the breakeven natural gas price of high GPM wells, but today’s low domestic prices for natural gas liquids (NGLs) have minimized the allure of targeting rich gas for many producers.

Southwest Appalachia Wellhead GPM (2013-Present)

Due to the relative isolation of Appalachia away from most domestic NGL fractionation capacity in the Mont Belvieu and Conway markets, recovered liquids transportation and fractionation (T&F) costs in the region are relatively higher than most other basins. The heavier NGL products must be recovered due to pipeline specifications, but producers typically have the flexibility to recover or reject ethane. In order to determine if ethane recovery is economically advantageous, the incremental costs of recovery must be weighed against the difference in pricing for selling the ethane as ethane rather than in the natural gas stream at in-basin natural gas pricing. Based on BTU’s cost estimates and March 2020 average basis pricing at Dominion South, rejecting ethane was more economic than recovery. It is important to note that both T&F costs and outright in-basin natural gas pricing are functions of operators’ negotiated agreements with midstream entities, so individual operators may realize different economic advantages based on their respective marketing agreements.

Based on 2019 completion activity, Antero Resources, Range Resources, and Southwestern Energy were the top three E&Ps targeting wet gas in the northeast. By securing access to international markets , northeast liquids producers with robust marketing business units gain access to potentially better pricing than the Mont Belvieu market, where the majority of US fractionation capacity, NGL demand, and pricing points are located.


Due to the lack of NGL benchmark pricing points outside of Mont Belvieu and Conway, the E&P Positioning Report utilizes Mont Belvieu pricing less transportation and fractionation to model NGL revenue. This method of setting liquids pricing is applicable to most US shale plays due to the widespread convergence of y-grade there, but it can neglect some Appalachian producer-specific opportunities for arbitrage with liquids pricing in Europe. As such, some Appalachian operators with robust marketing programs might have opportunities to capture additional liquids uplift compared to their peers with less sophisticated marketing groups.

Purity product prices at Mont Belvieu typically follow movements in the WTI crude price unless physical constraints or major changes in the supply/demand fundamentals for any specific purity product drive price volatility.

One example of an anomalous relationship to WTI occurred when ethane prices strengthened in mid-2018 due to a wave of new ethane crackers coming online with bottlenecks in downstream infrastructure to meet the new demand. This pricing strength spurred an increase in ethane recovery while infrastructure debottlenecking projects were underway. Subsequently, most purity product prices weakened relative to WTI from the fourth quarter of 2018 through the fourth quarter of 2019. More recently, as the crude prices fell rapidly in 2020, purity product prices did not decline proportionately. This led to abnormal pricing relationships to WTI, which is highlighted in both the chart above and table below.

NGL Price (% of WTI)

BTU Analytics uses the NYMEX WTI and Henry Hub strip prices from the final day of the quarter to estimate breakevens for each E&P Positioning Report. NGL prices were historically captured at the same point in time, the last day of the quarter. However, the pricing relationships to WTI on March 31, 2020 were far from conventional due to extreme market volatility from the demand impacts of COVID-19 response measures. Outright propane prices closed higher than normal butane prices, and isobutane closed higher than natural gasoline, two relationships that were very abnormal based on NGL heat content.

BTU Analytics uses the NGL prices as a percent of WTI to model NGL revenue over the assumed 20-year well life, so the abnormalities of March 31, 2020 NGL prices would significantly skew the impact of NGLs. The March 2020 average NGL prices maintain the relationships to WTI that one would expect – weaker prices than the five-year average but with the purity products priced correctly by increasing heat content. As a result, the March 2020 average NGL prices as a percent of WTI were used for breakevens that use the March 31, 2020 NYMEX and Henry Hub strip prices.

Physical Constraints Supersede Economics

Ethane rejection appears to be more economic that ethane recovery in Appalachia today, but most producers are not able to reject the entirety of the ethane in their produced gross gas stream. Key pipelines in Appalachia have strict limitations for gas entering their systems, which requires gas processing plants to recover enough ethane to keep heat content within pipeline specs.

Rover, TETCO, REX, and CGT have slightly different heat content limits set by their tariffs, but the average spec limit is around 1,100 BTU/cf. Due to the interconnectivity of many interstate pipes out of the region, heat content must be managed to the lowest common denominator, meaning not all pipes can run at the upper limit of what their specs would allow. Based on recent flows out of Appalachia that have crested 1,080 BTU/cf, there is not much room for additional heat content from rejected ethane. As such, additional ethane recovery will need to occur should volumes from liquids-rich portions of the play continue to grow as a percentage of Southwest Appalachian gas production.  Because pipeline gas quality concerns are not accounted for in BTU’s breakeven modeling, which instead models rejection or recovery based on what produces superior economics for each region as a whole, breakevens for rich-gas wells in Appalachia could be slightly worse than estimated.

cal constraints in the form of pipeline specification limitations are not only impacting ethane recovery in rich gas plays like Southwestern Appalachia. The Bakken also faces increasing pressure to suppress the heat content of processed gas entering its primary gas takeaway pipe, Northern Border. Associated Bakken gas is typically quite rich with average GPM values over 10. Due to the high GPM of Bakken wells, large volumes of NGLs must be stripped from the gross gas production and transported to the Gulf Coast for fractionation. This is an expensive, long journey for Bakken y-grade, discouraging ethane recovery at today’s prices. Producers in the Bakken have historically been able to blend with dry Canadian volumes delivering gas on Northern Border into the mid-continent region without much concern.

The chart above shows the rising heat content of gas passing through Glen Ullin, a point on Northern Border downstream of the Bakken. Northern Border tariffs did not need to include heat content caps historically due to the naturally occurring balance between Canadian and Bakken volumes. However, regulations that have diminished Bakken flaring have brought greater Bakken volumes to Northern Border and have displaced greater amounts of Canadian gas. As such, heat content on the pipe is rising, and Northern Border appears likely to enact new rules forcing greater ethane recovery in the Bakken. Due to these shifting market dynamics, Bakken producers are likely to have to recover more ethane to meet pipeline specs, even if the basin’s T&F fees make it uneconomic to do so.


The value of NGLs is just one piece of the complex modeling that goes into understanding US shale economics.  Limited pricing data for NGLs means that purity product prices don’t necessarily reflect regional dynamics incentivizing producers to reject or recover ethane.  BTU Analytics’ economic models suggest that almost all regions should be in ethane rejection, but the reality on the ground is more complicated.

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