Wonders of US Shale: US Shale Benefits: The U.S. leads global petroleum and natural gas production with record growth in 2018

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From the numbers, look like offshore , deepwater is also at risk at below 50$/bbl




Rystad Energy: High stakes in store for subsea markets if oil falls to $50/bbl

The subsea market in 2019 will experience year-on-year growth for the first time since 2014, but the positive outlook is vulnerable to any substantial decline in oil prices over the next few years.




The subsea market in 2019 will experience year-on-year growth for the first time since 2014, but the positive outlook is vulnerable to any substantial decline in oil prices over the next few years.

“We expect the subsea market to thrive during the coming years, but market growth will be at risk if the oil price falls to $50/bbl,” says Henning Bjorvik, an analyst on Rystad Energy’s oil field service team.

Development this year is essentially locked in with brownfield opportunities and already sanctioned projects—but the oil price will dictate growth moving forward.

In a $60-70/bbl oil environment, the subsea market is poised to increase about 7%/year up to 2025. But a large portion of this activity is at risk if the price of Brent crude falls to $50/bbl. The consulting firm believes prices at that level would still be enough to support 5%/year growth in the subsea market through 2022, but after that the growth rate could fall to zero.

“Although we expect the subsea market to have one of the highest growth rates within oil field services, the segment is also more vulnerable to an oil price drop than the oil field services market in general. We see significant risks in terms of subsea spending as well as growth,” Bjorvik noted.

Segments with especially high exposure to greenfield activity, such as the subsea equipment and SURF (subsea umbilicals, risers, and flowlines) segments, are at risk of having growth slashed by almost 5%/year. This stands in stark contrast to the oil field services market, which exhibits around 3%/year growth at risk over the same timeframe.

This trend is echoed when looking at spending at risk from 2019 through 2025—close to 20% of spending in the subsea equipment and SURF segments is at risk, while about 10% of general oil field services market spending is at risk should the oil price fall from our base case estimate to $50/bbl.

Spending at risk is largely dominated by floater projects globally, but in Norway is manifested in subsea tie-back projects. No fewer than 16 projects with subsea expenditure between 2019 and 2025 are at risk on the Norwegian continental shelf, 14 of which are subsea tie-back projects.


“It is worth mentioning that operators have had a remarkable ability to cut costs during downturns, much helped by the oil field service industry,” Bjorvik said. “Should a lower price environment again become reality, we can be assured that the industry has a proven track record of survival and ingenuity.”

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A review of 29 fracking-focused oil and gas companies revealed “meager” cash returns in the second quarter of 2019.

The report, which was carried out by Sightline Institute and the Institute for Energy Economics and Financial Analysis (IEEFA), noted that only 11 of the 29 companies under review registered positive free cash flows and that the 29 companies combined generated $26 million in aggregate free cash flows.

These aggregate free cash flows were said to be “far too modest to make a significant dent in the more than $100 billion in long-term debt owed by these companies, let alone reward equity investors who have been waiting for a decade for robust and sustainable results”.

The report, which stated that free cash flow is a crucial gauge of financial health, highlighted that “disappointing” cash flows have “soured” investors on the sector.

It also noted that, at the close of 2Q, the oil and gas sector was near the bottom of the S&P 500 and stated that by August 15, the sector hit “rock bottom, with drilling, exploration and production, and equipment and services leading the decline”.

“There were winners and losers this quarter, but overall, the oil and gas sector is still underperforming on virtually every financial measure,” Sightline Institute’s Clark Williams-Derry said in a company statement.

“Fracking remains a highly tenuous proposition for investors,” Williams-Derry added.

IEEFA Director of Finance Tom Sanzillo said, “as underwhelming as these results were, they were an improvement over previous quarters”.

“Still, investors would do well to remain skeptical and view the sector as highly speculative,” he added.

Sightline Institute describes itself as an independent, nonprofit research and communications center. The IEEFA conducts research and analyses on financial and economic issues related to energy and the environment.

A full list of the 29 companies analyzed in the report can be seen below:

  • Apache Corporation
  • Anadarko Petroleum Corporation
  • Antero Resources Corporation
  • Chesapeake Energy Corporation
  • Continental Resources
  • Cabot Oil & Gas Corporation
  • Callon Petroleum Company
  • Carrizo Oil & Gas
  • Concho Resources
  • Denbury Resources
  • Devon Energy
  • EOG Resources
  • EQT Corporation
  • Diamondback Energy
  • Hess Corporation
  • Laredo Petroleum
  • Marathon Oil Corporation
  • Matador Resources Company
  • Noble Energy
  • Oasis Petroleum
  • PDC Energy
  • Pioneer Natural Resources Co.
  • QEP Resources
  • Range Resources Corporation
  • SM Energy Company
  • Southwestern Energy Company
  • Whiting Petroleum Corporation
  • WPX Energy
  • Cimarex Energy Company

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Flaring limits, bottlenecks to constrain Bakken shale growth

There is considerable potential to increase oil production from the Bakken shale to at least 2 million b/d from its current 1.44 million b/d, but flaring regulations and infrastructure bottlenecks are limiting production growth, according to GlobalData.



There is considerable potential to increase crude oil production from the Bakken shale to at least 2 million b/d from its current 1.44 million b/d, but flaring regulations and infrastructure bottlenecks in North Dakota are limiting production growth, according to London research and consulting firm GlobalData.

Bakken oil production is facing constraints associated with prescribed limits set by North Dakota on natural gas flaring. The state is currently flaring about 19% of the gas it produces—well above the 12% permitted by state regulations.

In a recent report, GlobalData states that in 2018, the major counties for crude oil and gas production in the Bakken shale were McKenzie, Williams, Mountrail, and Dunn—all in North Dakota. Continental Resources Inc., Hess Corp., Whiting Petroleum Corp., ExxonMobil Corp., and ConocoPhillips were the leading producers in the play in 2018.

“Bakken oil wells show competitive performances when compared to recently completed wells in the Permian basin and Eagle Ford,” said GlobalData oil and gas analyst Andrew Folse, but “to some extent, the actual potential of the Bakken play is not getting realized due to restrictions on the flaring of natural gas in North Dakota, as most of this flared gas is associated with oil-producing wells in the Bakken formation.” Folse said, “As long as gas infrastructure in the region does not expand, the pace of drilling new wells will be constrained and oil production from the Bakken will remain flat or grow at a low rate.”

The Permian basin, Bakken, and Eagle Ford are currently producing more than 83% of the country’s oil production. During this year’s first half, these three formations averaged 4.05 million b/d, 1.44 million b/d, and 1.43 million b/d, respectively. Permian production has increased by 9%, the Bakken about 1%, and the Eagle Ford has stayed constant throughout the year.

“Bakken wells exhibit the lowest breakeven price among the three shale plays at $30.50/bbl, mainly due to the exceptionally high 30-day initial production rates of over 1,250 boe/d observed in this play. Also, the Bakken total production stream is over 75% oil where the other plays are around 58%,” Folse said.


“Moreover, many Bakken operators are picking up the trend of drilling longer laterals and experimenting with completion designs. Companies are drilling laterals up to 12,000 ft. The general objective remains to increase the productivity of the new producing wells in a higher proportion with respect to the cost increase associated with these more complex wells,” he said.

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A 2019 Permian Output Surge May Impact Oil Prices




Over the next eighteen months, pipeline capacity from the Permian is expected to increase by 1.5-2.0 mb/d, including increased delivery capacity to export terminals. This should have a number of effects, mostly positive for producers, but other constraints will mean that a sudden surge should not be expected. Higher prices for Permian crude and greater volumes will be the primary results, although an increase in flaring might bring new pressure to regulate ‘wastage’ of gas. 

The EIA projects slower growth in production from the 4th quarter of 2019 to the fourth quarter of 2020 -- 0.99 mb/d versus 1.75 mb/d from 4th quarter 2018 to 4th quarter 2019. This could be partly due to lower capital spending by shale oil producers, but it still seems unusually low. 

Although pipeline capacity theoretically comes online instantaneously--pipelines have to be filled, pressure ramped up, and some testing will mean it will take place over days or weeks—the supply change should not be that strong. Instead, supply now moving by rail and truck will be switched to pipeline, at least until production exceeds capacity again. So, the market impact won’t be the same as, say, major oil fields in Libya going on- and offline suddenly.

There are also constraints on how quickly production can increase. The large and growing number of unproductive wells in the Permian suggests that new pipeline capacity, allowing for higher wellhead prices, will see a surge in well fracking/completions, depending on the availability of crews. 

Historically, the number of wells fracked in a given month in the Permian has been as high as 668 (October 2014) versus a recent level of 530, and the rate has increased as much as 20-30/month, sometimes much higher. It seems unlikely that the number of fracked wells can increase by more than 50/month, but since the typical well adds about 600-700 b/d of gross output, the implication is that Permian output could grow by an additional 30 tb/d per month, or 360 tb/d by December 2020 versus the year earlier amount.  This amount is probably incremental to existing projections. 





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Permian Frac Tracker Sees Bipolar Market


Recent reports about oil and gas industry conditions in the Permian Basin have been mixed. As this July 16 article from Bloomberg indicates, there is evidence that industry activity is slowing down. Earlier this month, however, Rigzone reported that analysts with a prominent energy research firm dismiss that notion.

The Bloomberg article assesses the Permian’s health in the context of rig counts and production levels. Meanwhile, the Rigzone article references average well productivity. Seeking another perspective on the matter, Rigzone has re-connected with Matt Johnson. As principal of Los Angeles-based Primary Vision, Inc., Johnson monitors the upstream through the prism of hydraulic fracturing activity. Through its “Primary Vision Frac Spread Count,” Johnson’s firm tracks metrics such as frac spreads, frac fleets and stimulation crews.

“They reveal fracturing activity by region, by operator and pumper,” Johnson said of the data his company reviews. He explained that his firm’s focus on location, job duration and operator/pumper correlations provides insights about the market, competition and activity levels.

In February of this year, Johnson told Rigzone that oilfield services (OFS) operations in the Permian could be on the cusp of an uptick. What does his firm’s frac spread indicator reveal about current market conditions in the region, and what does it suggest could happen through the rest of 2019? Read excerpts from Johnson’s latest conversation with Rigzone to find out.

Rigzone: When we chatted in February, Primary Vision was anticipating an “action-packed” spring and summer for Permian oilfield services firms based on improved crude prices, global supply and demand and favorable pressure pumper contracts. Did this scenario materialize? If so, how impressive was the rebound following the late-2018 drop-off in activity?

Matt Johnson: We anticipated that pricing would flip in pumpers’ favor as we drew closer to higher frac spread utilization rates out of the early part of the year. Our counts were solid, but what was shocking was the number of completions in the second quarter. We believe that more wells were completed in June 2019 than at any point this year. Depending on who you talk to and what you read this might seem unfathomable, but operators were completing more wells, with more consumables used and less spreads – lower utilization rates than we expected – during that month than we’ve seen this year.

I’ve traveled the globe this year showcasing our current products and things we have in beta and can share that the market is in a bipolar state. One day I can talk to a pumper who said this was the worst year ever, the other I can talk to a pumper who was fully utilized and is for the rest of 2019. I just spoke with an operator the other day that is positioned to dominate the fall because they keyed in on opening pipelines while another has wrapped up their completion schedule and is looking for additional investment. The proof is in the data, and operators marched strong through the end of June. The year-over-year seasonality shows a slowdown from the middle of July into early September. From there we think we’ll see a small pick-up, followed by a sleepy holiday season.

Rigzone: Have you noticed any surprises and/or particularly striking aspects of Permian OFS activity in the past six months?

Johnson: This may not be as shocking as it sounds, but we think the ramifications are big. We know that operators are doing everything they can to continue the push for cost savings, including looking much closer at direct-sourcing their consumables (water, proppant and chemicals). We also see a handful of new logistics/sourcing/scheduling service companies coming online. Think of a third party coming in between the pumper and the operator to schedule consumable sourcing/delivery, while the operator just rents the horsepower from the pumper. This will definitely lead to further pain in the pressure pumper market in addition to looming operator consolidation. 

Rigzone: What are some key trends you’re seeing among Permian operations and OFS firms nowadays, and what might we expect to see over the next six months?

Johnson: The continued push into alternative-powered/electric spreads. This market has a had substantial growth this year as maybe as much as 15 spreads are fully electric now versus single digits in 2018. Some alternative solutions seem really strong while we hear that ongoing continuity issues remain with spreads that are fully electric. A lot of this is just ground talk, but it does seem that some of the alternative power solutions might be the best bridge solution between a traditional pump and an electric-powered turbine for the majority.

To contact the author, email

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Let me spoil your party a bit:


image courtesy @Mike Shellman of

and you can always count on Enno from @shaleprofile for BS-free production stats

If I wouldn't be working in the industry I'd suspect you are a paid stooge. But nobody in the shale industry would bother. Intriguing...

  • Haha 3

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20 hours ago, DanilKa said:

Let me spoil your party a bit:


image courtesy @Mike Shellman of

and you can always count on Enno from @shaleprofile for BS-free production stats

If I wouldn't be working in the industry I'd suspect you are a paid stooge. But nobody in the shale industry would bother. Intriguing...

Name calling always works if you dont agree with someone else, great maturity and professionalism @ display !!!!!

  • Upvote 1

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BP Exits Alaska After 60 Years in $5.6 Billion Hilcorp Sale




" Alaska, like Canada’s oil sands and the North Sea, is receding into a second-tier oil province as field depletion, cost-cutting and the rise of shale diminish the appeal of those resources. "


" The state’s oil output has slumped from its heyday in the late 1980s as discoveries dried up and major producers sought easier-to-produce crude elsewhere, most recently from shale rock in Texas. Hilcorp, along with ConocoPhillips, is one of the few big oil companies still interested in investing fresh capital in the state, which is home to protected ecosystems. "





What Bloomberg Intelligence Says

The deal “is logical and should be well received, given its indebted balance sheet exceeds the guidance range. The move is also consistent with the company’s long-term strategic shift toward shale and gas/LNG exposure from legacy conventional oil.”"








Here is another  tid bit about BP and shale




South Texas Drilling Permit Roundup: BP makes Eagle Ford debut under new name


The U.S. arm of British oil and gas giant BP PLC submitted its first applications to drill in the Eagle Ford Shale since completing a $10.5 billion deal to acquire acreage in South Texas and other parts of the U.S.

BPX Operating Co., based in Denver, received approval from the Railroad Commission of Texas last week to drill seven new oil or gas wells about 2.5 miles northwest of Helena in Karnes County. It's the first time BPX has appeared on the drilling permit roundup or submitted an application in Texas.

Prior to October 2018, the company's American subsidiary operated under a different name. The company was renamed as the $10.5 billion purchase of about 470,000 acres in Texas and Louisiana that previously belonged to Australian company BHP Group Ltd. (NYSE: BHP) was finalized. Among those were 194,000 acres in the Eagle Ford Shale already producing an average of 90,000 barrels of oil equivalent per day from 1,400 drilling sites.

Prior to last year's purchase and renaming, BP (NYSE: BP) filed for drilling permits in Texas under at least three other names. While those subsidiaries collectively filed more than 1,700 drilling permit applications dating back to 1981, none of them, prior to last week's applications, were in Eagle Ford counties.

South Texas Drilling Permit Roundup

The South Texas Drilling Permit Roundup is a weekly review of new drilling permit applications filed with the Railroad Commission of Texas for a 67-county area of South Texas. For the full drilling data table, see below.

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Drilling Down: Exxon Mobil shows no sign of cooling off in Permian Basin

The dog days of summer are the hottest and Exxon Mobil is showing no signs of cooling off any time soon.

Exxon Mobil’s shale drilling arm XTO Energy is preparing for another round of drilling in the Permian Basin of West Texas. The company is seeking permission from the Railroad Commission of Texas to drill 20 horizontal wells split between Glasscock, Pecos and Midland counties.

Exxon Mobil has become the top driller in the state. So far this year, Exxon Mobil has filed for 500 drilling permits this year, compared to the 332 drilling permits EOG Resources of Houston, the second most active driller. More than 430 of Exxon’s permits are for projects in the Permian Basin.



We like to talk about the ongoing strength of the U.S. shale revolution – and that’s intentional because, like most Americans, we think continued leadership in producing natural gas and oil is a big deal.


This week the U.S. Energy Information Administration (EIA) underscored America’s energy influence, reporting that last year the U.S. led the world in natural gas and oil production, which it has done since 2014.

U.S. Natural Gas and Oil – Still No. 1

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(Bloomberg) -- Diana Cerny has an oil boom to thank for the packed tables at her restaurant in Carlsbad, New Mexico.

Gushing shale production has brought boot-clad workers from all over the world to this Permian Basin city less than an hour north of the Texas border. White F-150s filled the parking lot of the Pecos River Cafe on a recent morning after a light rain lifted the smell of concrete cooked by days of triple-digit heat.

Like a broad swath of West Texas, this sage-covered corner of New Mexico sits atop America's fastest-growing oilfield. On the Texas side, oil and gas producers can drill and frack with relatively few bureaucratic hurdles. In New Mexico, 90% of Permian production takes place on lands owned by federal or state government, meaning companies need additional approvals from either the U.S. Bureau of Land Management or the state’s Land Office and Oil Conservation Division. 

That sets up a classic test in a state that turned politically blue this year. New Mexico has to decide how far it’s willing to go with a proposed rule to limit methane emissions, a key part of the new Democratic governor’s efforts to fight climate change. She must balance concern for the environment with the possibility that stricter regulation could tap the brakes on accelerating production that, thanks to royalties and taxes, funds nearly half the state budget. Already, some drillers expect slower growth in Permian output.

Cerny knows where she stands. Drilling “is good for the economy, it’s good for Carlsbad.” She said she worries that tighter rules could send companies packing across the border to Texas.

It’s a topic getting special attention on this hot August morning. A 10-minute drive from the cafe, outside a sand-colored event center, a line is forming for a public meeting to discuss the proposed rule.

“We don’t want all these workers to leave,” said Rosemary Madsen, 64, a bartender at the Stevens Inn off U.S. Route 285, Carlsbad’s main drag. She’s standing in line with Kerri Crawford, a waitress there, who’s holding a bright green sign that reads: “We won’t let you plug our HOLES!!”

Governor Michelle Lujan Grisham, a former congresswoman who took office this year, is spearheading one of the country’s most aggressive plans to combat climate change: a move to 100% carbon-free power generation in 25 years. Now she's targeting methane, the main component of natural gas and a greenhouse gas that’s far more potent than carbon dioxide.

Lujan Grisham’s push comes as the Trump administration readies a plan to end direct federal regulation of methane leaks, even as some energy companies insist they don’t want the relief.

The governor is balancing her concern over the catastrophic effects of climate change with the state’s extraordinary dependence on oil and gas. Soaring Permian production was in large part responsible for the state’s budget surplus last year. Output from the shale play, the world’s biggest, is projected to hit a record in September. At the current rate, the basin will soon catch up with Iraq, OPEC’s largest producer after Saudi Arabia.

“It’s a juxtaposition for sure,” Lujan Grisham said while sipping coffee on a microsuede couch in the state’s capitol in Santa Fe. “I think the trap for too many elected individuals around the country is that they’re asked by some constituent group to pick one, and I’ve said New Mexico is going to pick every single opportunity and then be responsible at the same time.”

Lujan Grisham and other state officials are adamant that they’re not trying to stifle the industry.

“It’s not about a ban on fracking, a moratorium on drilling, a stopping of oil and gas production at all,” Jim Kenney, secretary of New Mexico’s Environment Department, told the Carlsbad meeting.

Companies themselves haven’t said much on the possible changes, probably because so little is known about what they’ll entail. To work out the details, the state is setting up a panel that will include representatives from both environmental and industry groups. No date has been set for a resolution.


The New Mexico Oil and Gas Association said it’s generally been pleased with how the preliminary talks have gone.

“The governor has been extremely collaborative with industry,” said spokesman Robert McEntyre. “We feel that the conversations have been productive.”

New Mexico is hot right now. Producers that tapped their acreage in more developed fields have moved into the Delaware Basin, a sub-play within the Permian that stretches across far west Texas and into Eddy and Lea counties in New Mexico.

“The production is better here than in Texas,” said Justin Mitchell, who works for an oilfield contractor. “But the oversight that they have here is such a pain in the ass. Every minute they make it a little harder.”

The current state of the natural gas market is making the methane problem trickier. U.S. prices are at their lowest seasonal levels in two decades, with local prices in the Permian sometimes going negative due to a lack of pipeline capacity. That’s forcing some producers to occasionally shut in oil production to avoid having to find someplace to put the associated gas, according to Chris Walls, a petroleum engineer at the BLM’s Carlsbad office.

Far more common is flaring, when oil producers burn off gas to get rid of excess fuel. It’s a practice in full view of Route 285 outside Carlsbad, where flames dot either side of the road. Flaring is actually more environmentally sound than the alternative -- venting, in which methane is released directly into the air. But unlit flares can combine with pipeline leaks and tank hatches accidentally left open to put methane in the air.

While the link between greenhouse gas emissions and climate change is clear, researchers say they don’t know the direct health effects of high exposure to methane. What has been shown is the smog-forming pollutants often found alongside methane emissions, including VOCs, or volatile organic compounds, can lead to symptoms including headaches and nasal irritation.

Concerns are compounded by the fact that in Lea County, 68% of children under 5 live within a mile of a well site, according to the Environmental Defense Fund. In Eddy County, it’s 80%.

Penny Aucoin, a former school bus driver, attributes her 17-year-old son’s chronic nosebleeds to two oil wells across the street from their house.

“I’m afraid that when the oil and gas goes away, when things are done, this town is going to be a ghost town,” Aucoin said. “And everything is going to be destroyed.”

At the Pecos River Café, where a half-dozen waitresses in maroon polos are topping off coffee and taking orders for breakfast burritos, owner Diana Cerny said she’s not too worried about the boom’s effect on the environment.

“Most people are OK with the fact that it’s bringing jobs and income to our city,” she said. “Everything is busy.''

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3 hours ago, ceo_energemsier said:

Name calling always works if you dont agree with someone else, great maturity and professionalism @ display !!!!!

for the record, I did not called you a paid stooge (because nobody would bother to pay) but genuinely intrigued what are you and what motivates you to flood this forum with stories portraying rather rosy picture of the tough low margin shale business (trust me on this, I'm living it)

  • Like 1

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Danika has a point. Couldn't you just attach a link to your sources and those interested could read them as opposed to copying them onto the page? It gets unwieldy to go through the discussion.

  • Upvote 1

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@Dennis Coyne, wondering if this estimate of future production decline from tight oil wells is matching your model. Thanks!


As a frac'er I cannot be happier but basic knowledge of economics stops my excitement on its tracks... Oil price needs to be tad higher and debt service cost tad lower for party to continue. Nothing is impossible in age of negative interest rates and possible competitive devaluation (these two may be mutually excluding). For sustainable business we need positive Cash Flow . Pls don't tell me about growth phase or future production; decline is such that we need payback in ~2 years.

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13 hours ago, ceo_energemsier said:

BP Exits Alaska After 60 Years in $5.6 Billion Hilcorp Sale

There is a buyer:

“Just as important is the price: BP’s Alaskan assets were bought for just 3.8 times their annual cash flow, meaning Hilcorp may earn its money back within four years, according to Dittmar.

In the past five years, while everyone from Exxon Mobil Corp. to Concho Resources Inc. spent billions to get a slice of the shale boom, Hilcorp picked up assets in New Mexico, Wyoming and other oil properties in Alaska.”

Edited by DanilKa

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Aramco Trading sells first U.S. West Texas Light crude to South Korea's Hyundai

SINGAPORE/NEW YORK/SEOUL (Reuters) - Aramco Trading Company (ATC) sold its first-ever cargo of U.S. West Texas Light (WTL) crude, with a South Korean refiner the buyer, as the Saudi Aramco unit expands its U.S. oil dealings to boost trade volumes, four people familiar with the matter said.

ATC is key to Saudi Aramco's strategy as it expands its refining and petrochemical operations to boost global sales. The trading unit has been buying U.S. crude from Texas refinery Motiva to re-sell in Asia, the people said.

ATC has been shipping U.S. oil such as West Texas Intermediate (WTI) Midland crude, Eagle Ford condensate and sour grade Mars to refiners in Japan, South Korea, Taiwan, Thailand and the United Arab Emirates since last year, they said.

It expanded that selection of U.S. crudes earlier this month, loading its first-ever 1 million-barrel cargo of WTL, the people said. The shipment is expected to arrive at Hyundai Oilbank's refinery in Daesan in October, they said.

This was also Hyundai Oilbank's first WTL crude purchase, two of the sources said.

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North America Tops LNG New-build Ranking

North America will account for approximately 73 percent of growth in new-build liquefaction capacity in the global liquefied natural gas (LNG) industry through 2023, according to a new report from the data and analytics firm GlobalData.

“North America is expected to add 26 new-build LNG liquefaction terminals during the outlook period,” GlobalData Oil and Gas Analyst Soorya Tejomoortula said in a written statement

The report – “Global LNG Liquefaction Industry Outlook to 2023 – Capacity and Capital Expenditure Outlook with Details of All Operating and Planned Liquefaction Terminals” – assumes 243 million tonnes per annum (mtpa) of new-build North America’s liquefaction capacity by 2023. The firm notes that announced projects make up the majority of the region’s new-build capacity.

Tejomoortula added that North America’s largest new-build liquefaction terminal will be NextDecade Corp.’s 27-mtpa Rio Grande LNG project near Brownsville, Texas. The facility, set to begin operations four years from now, will produce LNG from low-cost natural gas from the Permian Basin and Eagle Ford Shale,





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Why US energy investors are experiencing a crisis of faith

Shale glut, growth fears and tougher ESG standards weigh on crude producers

It is a tough time to be an investor in oil and gas stocks. Oil prices might be more than double the levels of 2016, when they sank below $30 a barrel, but the US exploration and production (E&P) sector, as measured by an index tracked by S&P Dow Jones, is trading at a 15-year low. The reasons for investor apathy are multiple, from long-term fears about the future of the fossil fuel industry to short-term concerns about the new breed of shale-focused drillers’ ability to generate cash. But the bearishness is unmistakable. Amid the broad sell-off, energy’s share of the market capitalisation of the S&P 500 has fallen to less than 4.5 per cent, down from about 15 per cent a decade ago. Today’s share is even lower than during the late 1990s dotcom boom, when tech stocks were rampant and oil prices collapsed below $10 a barrel. Some fund managers see an opportunity to pick up oversold shares cheaply, but many see much better opportunities to make money elsewhere.

“I used to put my money on oil and gas and go to sleep,” said Tom Sanzillo, director of finance at the Institute for Energy Economics and Financial Analysis, and a former manager of the New York State pension fund. “Apple looks a lot better than spending time on this dying industry.”
Edited by ceo_energemsier

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Sasol starts up cracker at Louisiana petchem complex

Sasol Ltd. has completed production test runs and achieved beneficial operation of the cracker at its long-planned Lake Charles Chemicals Project (LCCP), an integrated ethane cracker and downstream derivatives complex under construction in Westlake, La.



Sasol Ltd. has completed production test runs and achieved beneficial operation of the cracker at its long-planned Lake Charles Chemicals Project (LCCP), an integrated ethane cracker and downstream derivatives complex under construction in Westlake, La., near Lake Charles (OGJ Online, June 7, 2016).

As of Aug. 28, the 1.5 million-tonne/year ethane cracker continues to operate stably at a capacity utilization of about 50%, with the company continuing to focus on improving ethylene quality and advancing ramp-up activities in accordance with the project schedule, Sasol said.

Current output from the cracker is used by some of the complex’s existing downstream units, with the remainder sold to external customers.

Achievement of beneficial operations at the cracker follows first production of ethylene at the LCCP on Aug. 24 that was marginally below polymer-grade specification due to the complex’s acetylene reactor system that—before intervention from the catalyst supplier and technology licensor—did not perform as anticipated, the company said.

While completion of all other downstream derivative units at LCCP has continued to advance, the previously announced commissioning schedule for remaining units has changed

Currently, Sasol said it expects the timeline for LCCP’s remaining units to achieve beneficial operation to be as follows:

  • Low-density polyethylene unit: November.
  • Zeigler alcohols unit: January 2020.
  • Guerbet alcohols unit: March 2020.
  • Ethoxylation unit: January 2020.




While the technical issues and delayed beneficial-operation dates for remaining units has adjusted LCCP earnings before interest, tax, depreciation, and amortization (EBITDA) guidance for the 2020 financial year to $150-300 million from a previous $300-$350 million, overall cost guidance for LCCP remains unchanged at $12.6-12.9 billion, Sasol said.

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EPIC lowers spot rates on new pipeline from Permian to U.S. Gulf Coast -filing

EPIC Crude Pipeline LP has proposed a lower rate to transport crude oil on its new 400,000 barrel-per-day pipeline from the Permian Basin to the U.S. Gulf Coast, effective Sept. 1, according to regulatory filings this week.

* EPIC proposed to drop tariff rates for all volumes on the line to $1.35 a barrel, according to the filing with the Federal Energy Regulatory Commission (FERC) on Wednesday.

* The proposed rate is down from the current $2.50 a barrel tariff, which had already been reduced from $5 a barrel before the pipeline began operations in mid-August.

* The San Antonio-based pipeline operator also said it expects a Permian Basin origin point at the Advantage Pipeline, a short-haul line owned by Noble Midstream Partners LP and Plains All American Pipeline LP in Crane, Texas, to begin service by Sept. 15.

* Its main crude storage terminal at Robstown, Texas, near the state's coastline, was not in service yet, EPIC said in the filing.

* Deliveries had also not yet begun at Flint Hills Resources' crude terminal in Ingleside, Texas, its own waterside storage facility in Corpus Christi, Texas, and the nearby POTAC Terminal, owned by Pin Oak, a joint venture owned by Dauphine Midstream LLC and Mercuria Energy Group Ltd, the filing said. (Reporting by Collin Eaton in Houston Editing by Matthew Lewis)



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