US oil and shale output – Jun 2019

Published at 19:29 30 Aug 2019 by . Last edited 09:48 13 Sep 2019.

US crude production averaged 12.08 mb/d in June, lower m/m by 33 thousand b/d but higher y/y by 1.48 mb/d. The m/m drop, versus our expectation of a 50 thousand b/d m/m uptick, was driven by lower-than-expected production in June from Texas and New Mexico—combined, those states saw output fall m/m by 1 thousand b/d to 5.87 mb/d, in contrast to our 60 thousand b/d m/m growth expected from the Permian and Eagle Ford combined. Elsewhere, Oklahoma production was down by 58 thousand b/d m/m at 0.55 mb/d and Alaskan output declined by 20 thousand b/d to 0.46 mb/d, together outweighing the m/m growth logged in North Dakota (36 thousand b/d) and Colorado (19 thousand b/d).


Disappointing Q2 19 earnings results, driven by rising parent-child issues and strict capital discipline, have erased much of the upside to our 2019 production forecast. The ongoing shift to lighter production continued across the Permian in June, with preliminary data showing the overall gas-to-oil ratio in the basin rising to 3.5 mcf of gas per barrel of oil, versus 3.3 mcf of gas per barrel of oil on average in 2018. While our Permian crude production growth forecast for 2019 remains unchanged at 0.78 mb/d, our NGL growth forecast has risen to 0.43 mb/d and our dry natural gas growth forecast to 1.5 bcf/d. Gas flaring in the Permian remains high despite the linefill of the 2 bcf/d Gulf Coast Express (GCX) natural gas pipeline. Elsewhere, in the Bakken, Hess and others are already preparing to sidestep infill drilling issues experienced in the Permian and the Eagle Ford by using wider well spacing, but stricter gas flaring regulations will cap production growth until gas processing capacity rises later this year. Producers are turning to the completion of DUC wells across the US, with even the Permian showing a completion-to-new-drill ratio of 0.98 in June, vs 0.93 in May. In sharp contrast to US onshore shale basins, Gulf of Mexico drilling activity has surged. Offshore half-cycle breakevens are now competitive with onshore breakevens, and we expect GoM output to grow by 0.13 mb/d y/y in 2019, driven by the higher use of tiebacks (barring any further hurricane-related disruptions).


Financial results across the US E&P sector varied in Q2 19, but the focus remains on capital discipline. The sample of 34 small-cap producers that we monitor—which represent around 15% of total shale oil and NGLs output—reported negative free cashflow for the 30th consecutive quarter, of $550 million in Q2 19, despite aggressive attempts to rein in spending. Liquids output for the group was stagnant q/q at 1.78 mb/d. Meanwhile, among the 16 large-cap producers that we monitor, free cashflow rose to $2 billion in Q2 19 from -$3.6 billion in Q1 19, and production increased by 25% y/y (+1.05 mboe/d) to 5.3 mboe/d, supported by mergers and acquisitions (M&A) activity and comprised of 57% oil, 17% NGLs and 26% natural gas.

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