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Permian Basin 2018

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PERMIAN BASIN: MIDSTREAM 64 | October 2018 | hartenergy.com "Given this is a producer-backed project—for all practical purposes, even if this producer is mas- sive and is also a refi ner—we expect the project timeline will be more dictated by Exxon Mobil's development plans than the overall needs of the basin and, as such, may not be some 'race to mar- ket' type of endeavor." Meanwhile, why is Cushing pricing for WTI still relevant when more and more WTI is going to the Gulf Coast? Reuters took up the topic in April. Carlin Conner, SemGroup Corp. CEO, said, "I believe Cushing's next chapter is that it's going to become an offsite Gulf Coast storage center." Cushing's reign as the Nymex trading price for WTI was borne from the 1980s launch of Nymex WTI futures trading during the U.S. crude export ban that ended in late 2015. TPH analysts reported in early June that, with further Permian takeaway projects directed to the Gulf Coast, "we believe Permian operators will cease fl owing barrels to Cushing in favor of better priced, export-linked markets." Imperial's Haas wrote after the Exxon Mobil- Plains news, "Permian outbound congestion is real, but we believe the market has overre- acted." She anticipates WTI relief will come in early 2019. "Texas is a mature petroleum province criss- crossed by a dense network of pipelines, some of which can be repurposed, reactivated and upgraded within short time periods." That natgas Adding to the Mid-Cush equation is associated-gas production. Permian producers are expected to cap- ture associated-gas production, and that takeaway capacity is also full. TPH analysts estimated that the "gas wall likely hits at a similar time to crude—late 2018 into early 2019—and could prove an equal barrier to growth as increased fl aring may draw additional regulatory and environmental scrutiny." KeyBanc's Deckelbaum is less concerned. "We view natural gas as less of an issue as the region does not have basin-wide regulation on absolute fl aring volumes. Rather, restrictions are granted at the lease level during what is the most sensitive production timeframe—initial production." Meanwhile, Baird analysts drew a different conclu- sion: "The fate of Permian oil this summer looks set to come down to the [Texas Railroad Commission (RRC)]. Natural gas export capacity is maxed out. "To keep the oil fl owing, producers will need to fl are, fi nd excess capacity elsewhere or shut in production. Producers can receive a 45-day permit from the [RRC] to fl are gas for a maximum of 180 days, primarily for casinghead gas. … Rare excep- tions for long-term fl aring may be made in cases where the well or compressor is in need of repair." SunTrust upstream analyst Neal Dingmann wrote that the RRC "plays ball, but the New Mexico Oil Conservation Division may not." Many Perm- ian producers have gas takeaway contracts, but "several companies have nothing fi rm." He expects Texas "will allow mostly all needed Permian natural gas fl aring," but New Mexico won't. "This would be pressure on the northern Delaware Basin operators." Imperial's Haas reported, "Natural gas transport capacity is tight, but most of the public companies under our coverage have secured outbound trans- portation arrangements and will have fl ow assur- ance, in our opinion. "However, companies will still take varying degrees of revenue hit, as it is diffi cult to hedge for Permian-gas basis differentials. We believe that smaller, private E&Ps might become 'swing produc- ers,' opting to slow down with unfavorable differen- tials and help ease the congestion, and more related consolidations could be on the horizon." Q "While we believe Permian challenges may be temporary, being selective has never been more critical." —David Deckelbaum, KeyBanc Capital Markets Inc.

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