Reported by Mason McLean, Energy Analyst, S&P Global Platts
The rise of WTI prices over the course of the year has brought with it considerable activity in liquids-linked areas over the course of the year. However, areas such as the Permian and the Rockies have pushed production so high to the point of creating a constrained environment. Constraints have been a part of the US oil and gas market, particularly on the gas side, for a few years now.
With the Appalachia region driving most of the US gas market since at least 2015, the supply has been limited only by the amount of takeaway capacity. Projects such as Rockies Express Zone 3 East-to-West, Rover, and
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TransCanada’s Leach Xpress allowed for northeastern US production to jump from 19.6 Bcf/d in 2015 to 27.2 Bcf/d this year to date.
As US NYMEX crude prices have pushed to about $66/bbl for the year, incentivizing increased producer activity, this problem has popped up in new areas, such as the Permian and the Rockies.
With the increase in oil prices, Platts Analytics calculates the Permian Midland Internal Rate of Return (IRR) has increased from 30% to 50% since October 2017 and has been maintained in the top 3 highest IRRs for North American oil and gas basins. Midland oil breakeven prices are among the lowest in the US at $39.75/Bbl. That said, production in the basin has slowed over the past few months, with constraints being hit on both the crude and gas side. It is the absence of access to crude transport which has resulted in a significant rise in DUCs.
In spite of the month-to-month increase in the price of WTI by more than $4/bbl, transportation challenges are likely to keep a relative lid on the forecast for Permian production for the balance of 2018. That said, with additional oil takeaway capacity slated to enter service at the end of 2018 and into early 2019, Permian supply is expected to resume its growth trajectory as the year progresses.
Additionally, within the Rockies, oil drilling in the Denver-Julesburg area has been driving much of the Rockies region activity as a whole. However, this production has stalled over the course of the summer; DJ gas production has largely leveled off since the beginning of the summer season, averaging 1.85 Bcf/d over that time frame. This also happens to be within 10 MMcf/d of the 30-day average. This stagnation has come as gross gas production has pushed to the processing capacity in the basin since April, a constraint that is anticipated to be alleviated shortly with new facilities scheduled to come online later this year.
Ultimately what this amounts to is that timing of new pipeline projects on both the oil and gas side of things will be critical in determining if and when production may slow in these critical areas.
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