Mikaila Adams
Editor-News
Favorable geology combined with technological and operational improvements have contributed to the Permian region becoming one of the most sought-after in the US for crude oil production. Of the growth expected to propel US oil production to 10.7 million b/d in 2018 and 11.7 million b/d in 2019—surpassing the previous record of 9.6 million b/d set in 1970—roughly half is projected to come from the Permian region, according to the US Energy Information Administration’s August Short-Term Energy Outlook. EIA expects Permian regional production to average 3.3 million b/d in 2018 and 3.9 million b/d in 2019.
While the overall trajectory will be one of growth, transportation bottlenecks resulting in depressed wellhead prices are expected to slow the pace of crude oil production growth in 2019 compared with 2018.
Looking at the Lone Star State in its entirety, the Texas Railroad Commission estimated Texas’s June oil production at 98.9 million bbl—a 7% drop from the prior month, and a 2% drop year-over-year.
The Eagle Ford, a not-so-distant industry darling, may regain some spotlight. Regional production is projected to increase by about 105,000 b/d from 2018 to 2019 to average 1.5 million b/d, EIA said. The geographic footprint is smaller, with fewer prolific formations and fewer drilling opportunities than the Permian, but it doesn’t suffer from the same pipeline capacity constraints. Producers may move away from the Permian in mid-to-late 2018 and 2019 into the Eagle Ford while the Permian region pipeline transport is constrained, the agency continued.
ESAI Energy analysts weighed in on Permian pain points following an evaluation of shale producers. While second-quarter operating costs in the Permian basin fell, on average, about 6% from year-ago levels, overall full-cycle breakeven costs are about 30% higher due to increased capital spending.
“Acreage consolidation is key for achieving scale, and will be critical to some producers’ bottom lines, but it comes at a cost. Permian acreage can be expensive,” said ESAI Energy analyst Elisabeth Murphy in an Aug. 22 research note.
As producers await additional takeaway capacity, Permian production will decelerate and drilled but uncompleted wells (DUC) will rise.
In July, 167 additional DUCs were added to the Permian region, EIA information showed. At its last count, the 3,470 Permian DUCs accounted for nearly 43% of all US DUCs.
The rising number of DUCs and the eventual growth in takeaway capacity indicates the potential for an impressive production rebound later in 2019, ESAI Energy analysts said. Even so, annual average Permian production growth is expected to slow significantly in 2019 compared to growth of over 800,000 b/d this year.
Progress is being made to relieve the Permian bottleneck—a logistical dilemma not unlike that seen in Appalachia where producers also slowed production for a period of roughly one year, said Rob Thummel, managing director and portfolio manager-energy, Tortoise Capital Advisors.
The Appalachian region is a little further along. If it were a baseball game, Appalachia is “probably in the 7th, 8th, 9th inning as far as getting this infrastructure in the ground and starting to see the basis differentials decline,” Thummel told OGJ in early summer. At that time, the Permian appeared closer to the 2nd, 3rd, or 4th. A couple of months after that call, the industry is hoping it is now closer to the latter.
For now, the Permian differential is here and it’s real. “Producers are entering deals locking in a $10 to $12 basis differential in 2019,” he said at the time, resulting in potential production decreases of 300,000-400,000 b/d. The wildcard is the timing of the EPIC pipeline. Thummel concluded: “If they could get that up and running sooner rather than later in 2019, it changes the game.”
