The magic number to keep the shale boom going is $55

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The magic number to keep the shale boom going is $55

 

The assumption that U.S. oil production will continue to rise, undeterred by anything other than some sort of severe disruption, gets questioned in a new report by Morningstar, which lists $55/barrel as the key number to keep the shale boom alive. 

“If prices stay above $55/barrel, production will continue to grow in sweet spots like the Permian Basin,” according to the August 5 report, written by Morningstar oil and products research director Sandy Fielden. There are other basins that aren’t “sweet spots,” Fielden writes, citing the Oklahoma Cana Woodford play and to some degree North Dakota’s Bakken because of the long distance to export ports. “So if prices drop below $55 for a sustained period, then the current production stall could turn into a bust. As soon as production starts to fall, exports will follow suit.”

West Texas Intermediate on the CME on Monday dropped almost $1/b to settle at $54.69. While prices settled below $55 on August 1 after a big trade war-created selloff, the fact is that WTI prices have not been consistently less than $55 since late June. 

In a telephone conversation, Fielden was asked about the report’s lack of a mention of another fact that some analysts are forecasting could result in a reversal in U.S. production growth – a tightening of the credit lines of the shale drillers. The continuation of that drilling, Fielden said, “boils down to the break-even point,” which is $55. And while many banks are tightening their financing to the independent drilling sector, Fielden noted that “Chevron and ExxonMobil are loosening their purse strings. Somebody is going to go in and get the oil if it’s above $55,” he said.

The biggest issue will be whether demand justifies growing supplies and prices adequate to keep the drilling boom alive. “If demand is growing and supplies tighten – helped by sanctions and the OPEC curbs –  then the resulting higher prices will support the shale production/export cycle,” the report said. 

 

Geopolitics holds two possibilities, according to the report, one in which OPEC and Russian-led non-OPEC restraints fall by the wayside and “new demand doesn’t absorb surplus production,” leading to a weakening of prices. If that happens, “we can expect another price crash along the lines of that seen in 2015,” though the lowest part of that crash actually came in 2016 when WTI bottomed at less than $30/b. But “that is not a scenario OPEC or its partner Russia relish, and they have shown strong discipline over the past three years.” 

The biggest risk then comes from weaker demand, according to the report, with the U.S.-China trade dispute the most likely force that would cause it to crater. 

Whether U.S. output is declining is a subject of some debate. The Energy Information Administration (EIA) puts out a weekly number. In its most recent weekly report, after U.S. production got hammered by Tropical Storm Barry in July and output was knocked down to an estimated 11.3 million barrels per day (b/d), the EIA reported last week that it was back up to 12.2 million b/d.

But in the most recent monthly EIA report, released last week for May data and considered to be more accurate, output was listed at just over 12.1 million b/d, down slightly from April. More notably, that full month figure was under the weekly numbers produced that month – two weeks when it was reported at 12.2 million b/d, one week at 12.1 million b/d, one week at 12.3 and one week at 12.4. (The report is released Wednesdays and there were five Wednesdays in May.) The final numbers, therefore, were significantly less than what the weekly numbers were projecting.

Whether the oil supply boom is at an inflection point is discussed in the Morningstar report. “The implication of weaker prices since the end of last year might be that the production boom of 2017 and 2018 is coming to an end and that output and exports will stall in the balance of the year,” the report said. But Fielden cautions that there is new pipeline capacity coming on in the Permian later this year, which will end the producers’ problem of having severely discounted oil in that region because of a lack of takeaway capacity. “And although the drilling rig count is down, rig productivity and total output continue to grow,” the report added.

The report noted that while the traditional Brent/WTI spread is one factor in determining the level of U.S. exports (which can help keep the shale boom going if they are healthy). But a more important number might be the spread between Brent and WTI at the Magellan East (MEH) terminal in Houston, as that is a number that better reflects the value of U.S. domestic crude relative to other global crudes. While the Brent to WTI Cushing spread has been holding near $6.50 to $7.50 per barrel in recent weeks, the spread to WTI at MEH has been far more narrow. It has held at or above $2/b since January 2017, the report said, “a wide enough margin to cover freight costs to Europe and Asia, keeping exports competitive.” 

 

Additionally, the spread didn’t narrow when crude prices collapsed at the end of last year, “indicating that surplus U.S. production still needed to be cleared into overseas markets with an attractive discount.”

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22 minutes ago, ceo_energemsier said:

The magic number to keep the shale boom going is $55

 

The assumption that U.S. oil production will continue to rise, undeterred by anything other than some sort of severe disruption, gets questioned in a new report by Morningstar, which lists $55/barrel as the key number to keep the shale boom alive. 

“If prices stay above $55/barrel, production will continue to grow in sweet spots like the Permian Basin,” according to the August 5 report, written by Morningstar oil and products research director Sandy Fielden. There are other basins that aren’t “sweet spots,” Fielden writes, citing the Oklahoma Cana Woodford play and to some degree North Dakota’s Bakken because of the long distance to export ports. “So if prices drop below $55 for a sustained period, then the current production stall could turn into a bust. As soon as production starts to fall, exports will follow suit.”

West Texas Intermediate on the CME on Monday dropped almost $1/b to settle at $54.69. While prices settled below $55 on August 1 after a big trade war-created selloff, the fact is that WTI prices have not been consistently less than $55 since late June. 

In a telephone conversation, Fielden was asked about the report’s lack of a mention of another fact that some analysts are forecasting could result in a reversal in U.S. production growth – a tightening of the credit lines of the shale drillers. The continuation of that drilling, Fielden said, “boils down to the break-even point,” which is $55. And while many banks are tightening their financing to the independent drilling sector, Fielden noted that “Chevron and ExxonMobil are loosening their purse strings. Somebody is going to go in and get the oil if it’s above $55,” he said.

The biggest issue will be whether demand justifies growing supplies and prices adequate to keep the drilling boom alive. “If demand is growing and supplies tighten – helped by sanctions and the OPEC curbs –  then the resulting higher prices will support the shale production/export cycle,” the report said. 

 

Geopolitics holds two possibilities, according to the report, one in which OPEC and Russian-led non-OPEC restraints fall by the wayside and “new demand doesn’t absorb surplus production,” leading to a weakening of prices. If that happens, “we can expect another price crash along the lines of that seen in 2015,” though the lowest part of that crash actually came in 2016 when WTI bottomed at less than $30/b. But “that is not a scenario OPEC or its partner Russia relish, and they have shown strong discipline over the past three years.” 

The biggest risk then comes from weaker demand, according to the report, with the U.S.-China trade dispute the most likely force that would cause it to crater. 

Whether U.S. output is declining is a subject of some debate. The Energy Information Administration (EIA) puts out a weekly number. In its most recent weekly report, after U.S. production got hammered by Tropical Storm Barry in July and output was knocked down to an estimated 11.3 million barrels per day (b/d), the EIA reported last week that it was back up to 12.2 million b/d.

But in the most recent monthly EIA report, released last week for May data and considered to be more accurate, output was listed at just over 12.1 million b/d, down slightly from April. More notably, that full month figure was under the weekly numbers produced that month – two weeks when it was reported at 12.2 million b/d, one week at 12.1 million b/d, one week at 12.3 and one week at 12.4. (The report is released Wednesdays and there were five Wednesdays in May.) The final numbers, therefore, were significantly less than what the weekly numbers were projecting.

Whether the oil supply boom is at an inflection point is discussed in the Morningstar report. “The implication of weaker prices since the end of last year might be that the production boom of 2017 and 2018 is coming to an end and that output and exports will stall in the balance of the year,” the report said. But Fielden cautions that there is new pipeline capacity coming on in the Permian later this year, which will end the producers’ problem of having severely discounted oil in that region because of a lack of takeaway capacity. “And although the drilling rig count is down, rig productivity and total output continue to grow,” the report added.

The report noted that while the traditional Brent/WTI spread is one factor in determining the level of U.S. exports (which can help keep the shale boom going if they are healthy). But a more important number might be the spread between Brent and WTI at the Magellan East (MEH) terminal in Houston, as that is a number that better reflects the value of U.S. domestic crude relative to other global crudes. While the Brent to WTI Cushing spread has been holding near $6.50 to $7.50 per barrel in recent weeks, the spread to WTI at MEH has been far more narrow. It has held at or above $2/b since January 2017, the report said, “a wide enough margin to cover freight costs to Europe and Asia, keeping exports competitive.” 

 

Additionally, the spread didn’t narrow when crude prices collapsed at the end of last year, “indicating that surplus U.S. production still needed to be cleared into overseas markets with an attractive discount.”

This is like people feeding the bears at Jellystone National Park.  Stop it.  Let nature take its course. 

The economics of shale have changed.  Propping up failed business models based on $100 oil is inefficient.  

Shale isn't dying .  .  .  It's just changing.

Edited August 12, 2019 by SKEP

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Permian Continues to Test the Limits of America’s Existing Midstream and Downstream Infrastructure

 

Austin, TX – Drillinginfo, the leading energy SaaS and data analytics company, has released Permian to Gulf Coast Midstream, the latest installment of their FundamentalEdge series, which presents an overview of oil, gas, and natural gas liquids (NGL) infrastructure currently proposed between the Permian basin and Gulf Coast export terminal locations.

Underscoring the lack of adequate takeaway capacity in 2018-2019, plus the expected importance of coastal oil, natural gas, and NGL exports, in this report Drillinginfo highlights the expected impact of upcoming long-haul takeaway capacity projects and the price differentials they’ll create.

“The Permian basin has experienced unprecedented production growth and remains the world’s focus, from producer to private equity, to service and supply companies,” said Bernadette Johnson, Vice President of Strategic Analytics at Drillinginfo. “But the Permian continues to be challenged by existing pipeline constraints and the inability to efficiently and effectively move oil, natural gas, and NGLs to the market. All hydrocarbons are tied at the drill bit and one affects the other.  Although many players in the Permian are targeting crude oil primarily, natural gas processing and pipeline bottlenecks can have a negative impact on that crude oil production. However, a light at the end of the tunnel may soon be visible – at least for those that can hang in there through 2020,” said Johnson.

 

 

 Drillinginfo analyzes numerous planned pipeline projects and the bottlenecks they expect will be cleared providing relief to America’s most prolific, but congested basin.

Key Takeaways from the Report:

• Production growth in the Permian basin is testing the limits of existing midstream and downstream infrastructure, requiring further capital investment in long-haul pipelines, gas processing plants, NGL fractionators, and coastal export terminals.
• Crude oil production continues to rise in the Permian basin despite economic headwinds resulting from sub-$60/bbl WTI prices. Nevertheless, the pace of growth is at risk of slowing significantly if the low flat-price environment persists. With additional long-haul pipeline capacity coming online in the second half of 2019, noncommitted shippers will likely find themselves squeezed out as spot arbs shut. As volumes are further increased to the Gulf Coast (and away from Cushing), additional export capacity will be required, and there is an acute need for new export facilities capable of fully loading VLCCs. A race to the finish has begun, with numerous onshore and at least seven offshore terminals currently proposed or in development.
• Although natural gas production is mostly a by-product of drilling for crude in the Permian basin, flaring is just not a long-term option. In DI’s high case scenario, dry gas production could increase by 50% (~5 Bcf/d) over the next five years.
• Market participants are also facing weak regional pricing, with Waha basis trading at levels more than $1.00/MMBtu under Henry Hub. Hence, at least five projects are currently proposed to alleviate this constraint. All projects will be transporting the gas east toward South Texas and Louisiana to feed LNG exports as well as growing power and industrial demand.

NGL production out of the Permian is expected to continue to grow, with most of the production destined for the Gulf Coast. To allow for the extra production, a number of pipeline projects are under construction or in planning to transport the NGLs. As NGLs arrive at the Gulf Coast, they are then fractionated. Fractionation capacity has been running tight since mid-2018, resulting in numerous fractionation projects along the coast. The fractionation bottleneck was relieved slightly in early 2019, when two projects hit the market. However, with most projects scheduled to come online in early 2020 and after, it is possible the bottleneck will reappear in late 2019 and early 2020.