Ethane Recovery Outlook in 2020

January 7th, 2020 | LPG Liquefied Petroleum Gas

As most of us following energy markets know, 2019 was not a strong year for natural gas liquids pricing. Ethane was priced at just 17 cents per gallon at market close for the final day of trading in 2019, down from just over 29 cents per gallon on December 31, 2018. Despite a 41% price decrease year over year, ethane recovery might make more sense than you think. Today’s commentary will explore where and why ethane recovery might be making a comeback in 2020.

While ethane prices have diminished in 2019, the general trend has mostly mimicked Henry Hub pricing weakness. Over the summer, ethane prices dipped significantly due to weak regional natural gas prices, which prompted producers to recover ethane rather than pay to ship more associated gas particularly in the Permian where outright prices were negative. Conversely, ethane failed to rally when Henry Hub prices climbed over 30% at the beginning of November, remaining flat near 20 cents per gallon. With transport fees varying widely between basins, does it really make sense to recover ethane at its current pricing near multi-year lows? The answer is: it depends.

The Bakken, for example, is a NGL-rich basin that makes a poor case for ethane recovery. If ethane (and a small amount of incremental propane) is recovered, fractionated, and sold as a liquid, it would generate about $0.43/MMBtu of revenue in excess of if it was kept in the gas stream and sold based on its heat content. However, with such a long distance to transport NGLs stripped at Bakken gas processing plants, transportation costs to reach Mont Belvieu are some of the highest among the major basins. Therefore, the costs incurred by recovering Bakken ethane are economically prohibitive, leaving natural gas pipeline heat content constraints as the primary driver for additional recovery.

With the average December 2019 Henry Hub spot price at just $2.20/MMBtu, weak basis pricing begins to play a much greater role in the decision to recover ethane. For example, Waha’s average basis was $(1.06)/MMBtu in December, leaving outright prices at just $1.14/MMBtu at the Permian hub saturated with associated gas production. This glut of gas drove outright prices negative at Waha in mid-2019, which incentivized ethane recovery regardless of NGL prices. The completion of Gulf Coast Express provided much needed relief to natural gas takeaway constraints in the Permian, but Waha’s basis remains wider than most natural gas hubs in the US today. As a result, the Permian is right on the tipping point of being in economic recovery of ethane as highlighted in the chart below.

The chart above highlights the gain in ethane prices needed to reach economic recovery for several basins. Assuming flat propane prices, a $0.19/gal ethane price increase would be required to offset transportation and fractionation costs for Bakken NGLs. The case is less dire for the DJ Basin, requiring only a $0.10/gal ethane price hike, but this still remains unlikely given the saturation of NGLs from US associated gas production. Permian producers, the culprits responsible for driving associated gas production growth, are very close to negligible loss (or benefit) for recovering ethane given weak in-basin natural gas prices. Specific contracts will vary, but at the aggregate level, Permian ethane recovery economics could swing either way depending on commodity prices. Lower in-basin natural gas prices will tip the scale in favor of economic ethane recovery.

Ethane recovery in most basins remains difficult to justify, but regional market dynamics prove that ethane recovery might become more prevalent in 2020 as natural gas reaches multi-year lows.  Request more information about BTU Analytics’ Gas Basis Outlook service to learn about our process for forecasting regional pricing at Waha and many other hubs. For NGL production forecasts, check out our Upstream Outlook.

Author: Hamp Smith

Hamilton (Hamp) Smith is an Energy Analyst at BTU Analytics, focusing on the publication of BTU’s E&P Positioning Report. He also oversees oil and gas production forecasting for the Rockies. Prior to joining BTU Analytics, he was a hydraulic fracturing field engineer at BJ Services. Hamp holds a B.S. in Petroleum Engineering and M.B.A. in Energy Management, both from the University of Wyoming.