Magic of Shale: EXPORTS!! Crude Exporters Navigate Gulf Coast Terminal Constraints

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Electric motor developer, US Well Services sign on for frac fleet


A pioneer in electric-powered hydraulic fracturing technology is making its relationship with a electric motor developer official. U.S. Well Services Inc. has entered into an official agreement with AmeriMex Motor & Controls LLC that will supplant AmeriMex as the main supplier of electric motors to the growing electric frac fleet owned and operated by U.S. Well Services.

The companies jointly developed the electric motor and have refined the system together after analyzing data from field operations performed by U.S. Well Services.

“We are pleased to formalize our long-time partnership with USWS.  They have been a pioneer in electric fracturing technology and remain the market leader in electric hydraulic

fracturing services.  U.S. Well Services’ extensive operating history using electric fracturing fleets is a testament to its unique position in this market.  We look forward to growing our relationship with U.S. Well Services and serving as a long-term partner for many years to come,” said Wade Stocksill, president of AmeriMex.

USWS is a technology-oriented oilfield service company focused exclusively on hydraulic fracturing services for the oil and gas industry. USWS is one of the first companies to develop and commercially deploy electric-powered hydraulic fracturing equipment. USWS’ patented Clean Fleet technology combines natural gas turbine generators with electric motors and existing industry equipment for hydraulic fracturing, offering numerous advantages over conventional, diesel-powered fracturing fleets.

Joel Broussard, president and CEO of U.S. Well Services commented, “Our partnership with AmeriMex and exclusive arrangement with its motors will strengthen our competitive advantage and support our ability to capitalize on increasing demand for electric fracturing services. These efficient, compact motors are the only field-tested motor with a proven track record in electric hydraulic fracturing.  AmeriMex has a solid history of developing long-lived electric motors for various applications in other industries, and these innovative 3,000 HP motors for electric fracturing are a key differentiator for our company and technology.”

In 2018, the company signed deals with clients in the Permian and Eagle Ford, expanding the usage of its electric frac fleet. The company has also listed on the New York Stock Exchange.  



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Stage Completions records 142-stage Permian shale well


Stage Completions has announced a record setting 142-stage completion, with the 5.5 inch Bowhead II Sliding Sleeve System Bowhead II system in the Permian basin. The fracturing operation was completed in 4.3 days (34 stages per day), placing 9.2 million pounds (4,600 tons) of sand at a maximum concentration of 4 ppg (480 kg/m3), and a maximum pump rate of 60 bbl/min (9.54 m3/min), with an average horsepower requirement of 4,300 hp.

The Bowhead II system runs a dissolvable ball on collet that activates sliding sleeves. The Bowhead II system has a constant ID through the wellbore that is cementable in place and allows for longer laterals, tighter spacing, higher pump rates, reduced HHP requirements, optimized water volumes for completions, and higher sand concentration. The Bowhead II system provides continuous pinpoint fracturing capability to operators without wireline or coiled tubing.


The Bowhead II system offers clear technical advantages with respect to controlled fracture placement and stimulation efficiency. Sean Campbell, president of Stage, stated, “The trending emphasis on choosing the best completion practice for each well application should lead the industry as a whole to favor the Bowhead II system. Stage strives to remain a leading technology innovator and continues to differentiate itself in the industry. Operators have placed a high priority on completion efficiencies that directly impact estimated ultimate recovery and return on investment during a well’s life cycle. After this large-scale completion, several operators are planning wells utilizing the 5.5” Bowhead II system.”

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Reveal releases FracEYE system to reduce frac hits in shale wells

To minimize the effect of frac hits in mutliwell pads, Reveal Energy Services has developed a new product it calls FracEYE. The monitoring system allows operators to make timely adjustments to wells being fracked on mutliwell pads that feature parent (previously completed wells) and child (recently drilled wells being completed in the same or near formation as parent well).

“Because infill development and frac hits are a pressing concern, our goal was to develop a service with a fast turnaround time so operators would have the information to update their next completion designs, if necessary,” said Sudhendu Kashikar, CEO or Reveal. “We’re pleased that we can add to the understanding of frac hits.”

According to the company, it all starts with its pressure-based technology. The system categorizes the type and severity of interwell communication by measuring the pressure response from a parent well as hydraulic fracturing proceeds normally in child wells. Geoscientists and completion engineers can use the pressure-response timing and geomechanics to classify the observed response into one of four categories:

-direct fluid transport: large and rapid overall pressure increase in the offset well 
-fluid migration: gradual pressure increase that lingers post-stage completion 
-undrained compression: instantaneous pressure response in the offset well
-no signal: no significant pressure change in the offset well

Reveal first signed a contract with a major operator in the Marcellus in June last year. Since then, the company has performed in multiple shale basins and received two patents for pressure based fracture maps.

Prior to joining Reveal, Kashikar was the vice president of engineering at Microseismic Inc. Reveal Energy’s board of directors includes representatives from Lime Rock Resources and Statoil Technology Invest.

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Titan tests, proves electric power tongs on DJ Basin rig

JCA Companies affiliate Titan Casing has partnered with one of the largest E&P companies in Colorado and Ensign USD to enhance oilfield safety and reduce environmental concerns on drilling locations. By utilizing a drilling rig's hydraulic systems to operate casing power tongs, rather than diesel powered Hydraulic Power Units, Titan Casing has made a large step forward in making drilling locations safer, more economical and environmentally friendly.

This new process cuts down on diesel consumption, potential hazardous spills and work site traffic obstacles on drilling locations. Furthermore, the noise reduction is substantial, which benefits those residential or commercial properties in close proximity.

Erik Rodriguez, Titan Casing vice president, said, "On October 26, 2018, on Ensign 152 in the DJ Basin, Titan Casing ran a 17,000-foot


monobore well off of the public grid (line power) without the use of diesel motors in order to limit the carbon footprint of operations and to do our part to keep Colorado beautiful and green."

Titan was able to run casing at a rate of more than 1,300 feet per hour, which is as efficient than previous jobs using a 6-cylinder Diesel Duel Stage Power Unit. Titan's system completed the job with zero gallons of diesel used.

"We have put countless hours of research and development into making this system efficient and safe," said Rodriguez. "On our end we have changed all hydraulic valve banks to create a closed loop system as opposed to an open loop hydraulic system. This required several hours of trial and error as it has never been done before on a rig in this drilling contractor's fleet. With the help of Ensign tool pushers and our counterparts at our E&P partner we were able to further improve efficiencies on the wellsite."

On a typical casing job, Hydraulic Power Units require 30 to 35 gallons of diesel fuel, in addition to hydraulic fluid and oil. This new technology could save thousands of gallons of diesel fuel per rig annually in Colorado. In addition to being larger than a Volkswagon and taking up considerable space on locations, the hydraulic fluid, diesel fuel and oil that is used in these power units can leak or spill on locations. This new technology would limit hazardous spills such as these.   

Josh Allison, CEO of JCA Companies, said, "Titan Casing, C-MOR Energy Services and JCA Companies strive to develop innovative products that enhance oilfield safety and reduce carbon emissions on drilling and frac site locations. We are fortunate to work with partners who share the same goals in safety and the environment. Ensign has really made a push to create a safer, more economically friendly worksite and has worked with JCA Companies and C-MOR Energy Services to put the C-MOR Crown Jewel of several of their drilling rigs as well. JCA Companies and affiliates look forward to continuing our mission of making drilling locations safer, more economical and environmentally friendlier."

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Bakken to surpass record output despite gas bottlenecks

ESAI Energy reports crude and condensate production from the Bakken shale basin will surpass current record output into 2020. In the company’s recently published North America Watch, ESAI Energy points to increasing rig productivity and efficiency gains in areas outside of the Bakken core that are translating into high growth rates for the basin as a whole. Bakken production growth will add almost 250,000 barrels per day to total U.S. crude production over the next two years. 

Along with record oil output, the Bakken’s associated gas production is rising at an even faster pace, according to the ESAI Energy report. While crude oil production has increased by 19 percent over this time last year, natural gas volumes have climbed by 29 percent. The large increase in natural  gas production is continuing to strain gas processing capabilities, resulting in North Dakota failing to meet its gas capture goals. Although processing capacity is being added by the end of this year, constraints on NGL takeaway will last into 2020 when a new long-haul NGL pipeline will be completed. Despite these infrastructure bottlenecks, ESAI projects Bakken crude oil to reach 1.5 million b/d by the end of 2019 and continue to grow into 2020. 

“Unlike the other major shale basins, the Bakken is still showing large gains in rig productivity,” ESAI analyst Elisabeth Murphy explains. “If this productivity is sustained, it will create better economics for production outside of the core, giving producers more confidence to drill and complete more wells during a volatile oil price environment”.

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U.S. Oil Exports Rising Amid Middle Eastern Turmoil

Hostilities have lifted crude prices, sent tanker rates surging and opened a window for U.S. producers to sell more barrels abroad


U.S. crude exports are surging, reflecting strife along the Strait of Hormuz that has given oil buyers second thoughts about the Persian Gulf.

The hostilities, including attacks on oil tankers passing through the important supply route, have lifted crude prices, sent tanker rates surging and opened a window for U.S. producers to sell more barrels abroad, taking market share from the Organization of the Petroleum Exporting Countries in the process.


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US to lead oil output growth through 2030: ConocoPhillips chief economist


Global oil demand expected to rise modestly to 2030

Refining capacity will adapt to lighter US crudes

US crude export constraints seen as temporary


The US will lead global oil production growth for the next decade, and tight oil can continue to grow beyond the 2030s even moderate prices, ConocoPhillips chief economist Helen Currie told S&P Global Platts Tuesday.

ConocoPhillips expects OPEC net production growth of 2 million-3 million b/d during the next decade, while non-US/non-OPEC oil output will remain "a very big part of meeting the world's energy needs" during that period, she said.

"We find plenty of projects that can be developed at a moderate price level," Currie said of the global supply outlook through 2030.

ConocoPhillips expects modest global oil demand growth through the next decade.

US crude exports will keep rising as domestic production grows. They may face constraints at various times as Gulf Coast infrastructure is getting built, "but we don't foresee those being permanent issues," Currie said. "There are plenty of projects along the Gulf Coast."

While some analysts have questioned whether global refining demand can support the growth in US light crude being projected, Currie said she sees growing domestic demand in the form of announced expansions by Gulf Coast refineries and petrochemical plants.

"We are seeing signs of growth in refining and processing capability in the US for the lighter ends," she said.

ConocoPhillips also expects higher demand for US condensates and NGLs from buyers in Europe, Latin America and Asia.

"We think that will continue to grow. ... There's definitely appetite for light US molecules in the Asia market," she said.

Currie shared a more detailed oil market outlook Monday at the Center for Strategic and International Studies during a briefing held under Chatham House rules. She released some of the findings to Platts Tuesday.

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Shale ,  Another Decade of U.S. Supply Growth

(Bloomberg) -- The U.S. will account for almost a quarter of global oil and gas production by the early 2030s as the shale boom keeps on booming, according to the head of Rystad Energy.

Output from shale including crude oil, condensate and natural gas liquids could climb to as high as 25 million barrels a day, Jarand Rystad, chief executive officer of the research and intelligence company, said in an interview in Kuala Lumpur. The U.S. will likely make up about 23% of global liquids production and pump 27% of the world’s gas by then, he said.

Part of the reason for the expected growth is that companies are getting better at hydraulic fracturing, the process of pumping a mixture of water and sand into a horizontal well to create millions of tiny cracks in the shale rock that allow oil and gas to flow to the surface. Frackers are using more sand, creating more cracks and boosting the productivity of each well, Rystad said.

“It’s about sand, horsepower and water injection,” he said at the Asia Oil & Gas Conference. “Those three parameters are what’s driving activity levels, and those are three times higher today than they were back in 2014.”

Rystad has been a staunch believer in U.S. shale since early this decade when many analysts and OPEC ministers were unconvinced that a natural gas drilling revolution would translate to a surge in oil output. He recalled being labeled “ridiculously too aggressive” in 2012 when projecting shale crude production would grow fourfold to 4 million barrels a day within four years. The forecast was too low and shale has transformed the nation into the world’s biggest producer.


Looking ahead, Rystad’s optimism is also based on a recent study he’s done on the so-called parent-child interference issue, a concern that drilling a new well too close to an older one will reduce pressure in the original and cut output. While the results were mixed, overall the study showed that companies can stack wells more densely, creating enough drilling locations to support 10 to 15 more years of output growth, he said.

The shale surge underscores just how far the U.S. industry has progressed since former President George W. Bush promised to cut imports from the Middle East when he declared in 2006 that the country was “addicted to oil.” Now, said Rystad, the world is so dependent on American production that if fracking were ever banned it would cause a global energy crisis.

“Shale has become a drug that the world is addicted to,” Rystad said . “We cannot live without it. We’d never be able to compensate with OPEC and offshore production.”







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Let the whining begin!!! LOL







Edited by ceo_energemsier

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Why Rapid Production in Shale Development is a Perk


Since the early days of shale oil and gas production, some analysts have expressed alarm about the rapid decline that those wells experience, suggesting either that this will harm shale’s financial viability and/or lead to an early peak and decline in overall production.  But this attitude fails to acknowledge the benefits of producing a resource rapidly.

It is true that it seems inefficient to install capacity that will quickly be underutilized. No one builds a refinery that will see its utilization drop to 20 percent in a few years. But that is the nature of producing fluids; a field can be designed to produce at a constant rate, but only by offsetting the decline in individual well production, whether by enhanced recovery methods and/or additional drilling.

The contrary interpretation of rapid decline is that it represents accelerated production and thus, accelerated revenue accrual. Investment depends on capital and so revenue must be discounted by something roughly akin to the borrowing rate or desired rate of return, usually from 10 to 15 percent per year. In simple terms, money sooner is better than money later, all else being equal.

The first figure shows representative production curves for a conventional oil well, declining at 8 percent per year, and a shale well whose production drops 65 percent in the first year but flattens out thereafter. In each case, the total production (over eleven years) is about one million barrels. 


Considering the discounted cash flow, or revenue which is discounted by 12 percent per year from the initial year, the difference becomes a bit more clear. The second figure shows the discounted revenue for the same wells from 2019 to 2030. The shale well’s front-loading of revenue is clear and financially valuable; total net present value is $36 million versus $29 million for the conventional well in this example.   


There is another, somewhat speculative, benefit that shale producers are better positioned to exploit: the impact of supply disruptions. Although all commodities suffer from volatile prices usually due to influences that are not predictable in the medium term, like severe or beneficial weather, the oil industry is particularly prone to fluctuations that persist for a time.  As the figure below shows, the Arab Spring in 2011 disrupted Libyan production and tighter sanctions on Iran in 2012 caused its production to drop. While there were offsetting factors, incidents such as this increase the probability that prices will be elevated for a period of several years.


In such cases, being able to bring shale wells on-line and produce a large portion of reserves in 18-24 months can greatly increase the payout for a producer. Instability in a case like Libya’s can be expected to persist for the near-term future, but beyond that, the uncertainty grows. A deepwater platform that takes years to develop and extracts its reserves more slowly is at the whims of the market.

Naturally, there are many other factors that drive oil price cycles in the short-, medium- and long-term, but the accelerated production of shale wells leaves them uniquely positioned to take advantage of the peaks—and hopefully plateaus—in prices that occur from time to time, particularly when they are driven by effects that appear lasting, as with the Arab Spring. 

Overall, then, it is time for pundits to cease decrying the rapid decline in production from shale wells as a curse and recognize it as valuable.






Michael Lynch

I analyze petroleum economics and energy policy.

I spent nearly 30 years at MIT as a student and then researcher at the Energy Laboratory and Center for International Studies. I then spent several years at what is now IHS Global Insight and was chief energy economist. Currently, I am president of Strategic Energy and Economic Research, Inc., and I lecture MBA students at Vienna University. I've been president of the US Association for Energy Economics, I serve on the editorial boards of three publications, and I've had my writing translated into six languages. My book, "The Peak Oil Scare and the Coming Oil Flood" was just published by Praeger.


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A History Of Shale Pessimism: "Always With You It Cannot Be Done"

Recent reports about bankers’ demands that shale producers not increase upstream expenditure have caused some to be pessimistic about the outlook for shale production, up to and including last month’s “Shale Boom about to go Bust.”   Other stories have emphasized the poor financial performance of the sector, such as “A Gusher of Red Ink,” suggesting that shale is generally unprofitable and urging caution on investors.

 (Of course, as Robert Rapier points out, some appear to be using an incorrect measure of free cash flow by not treating depreciation and amortization as historical, not current, costs.)

Although there have been projections for shale supply that proved too rosy, the media attention often focuses on challenges facing the industry, implying bearish expectations.  Such pessimism is not new: it began with the initial skepticism about George Mitchell’s pioneering efforts to extract gas from shale and continued with an insistence that only gas from the Barnett shale would prove viable.  When other gas shales proved economical to produce, many insisted that oil molecules, being larger, would not flow through fracked shales.  When Bakken oil production proved successful, that success was attributed to the layer of dolomite which most other shales did not possess; when the Eagle Ford proved successful, it was said in 2013 that “each play is in effect its own ‘resource pyramid,’ characterized by a few small ‘sweet spots’.



Surging production from those and newer shales, notably the Permian, STACK and SCOOP, saw new concerns:  the rapid decline rate of shale wells would severely limit the supply available.   As one recent story put it, “The shale industry faces an uncertain future as drillers try to outrun the treadmill of precipitous well declines.”

This is similar to arguments long made by peak oil advocates: “a whole new Saudi Arabia [will have to be found and developed] every couple of years’’ to satisfy current demand forecasts.”  (Robert Hirsch, quoting Saddad al-Husseini 2005)  Unfortunately, he appeared not to notice the near-identical comment from Jimmy Carter in 1977:  “…just to stay even we need the production of a new Texas every year, an Alaskan North Slope every nine months, or a new Saudi Arabia every three years. Obviously, this cannot continue.”



Now, the arguments are focused on the supposed failure of shale producers to turn a profit.  “In the early stages of the fracking boom, investors tolerated negative cash flows from oil and gas producers, believing that the industry would eventually learn to produce cash as well as oil and natural gas. But most frackers never turned the corner. A few companies can now eke out modest positive cash flows, but the sector as a whole consistently fails to produce enough cash to satisfy its voracious appetite for capital.”

Again, this is not new. A 2011 story in the New York Times said “Money is pouring in” from investors even though shale gas is “inherently unprofitable,” an analyst from ... an investment company, wrote to a contractor in a February e-mail. “Reminds you of dot-coms.”  (The Times Public Editor subsequently suggested the article relied too much on the views of a few pessimists and inadequately explained that the story referred not to the industry as a whole, but to particularly aggressive independents.)

On the analytical side, many of these reports suffer from simplistic views, including a failure to recognize the dynamic nature of production methods.  The breakeven price in most if not all shales today is much lower than a decade ago.  Additionally, the massive losses that occurred when oil prices dropped in 2015 explain a lot of the poor performance of the industry when the returns of the past decade are aggregated.

But many of the pessimists appear to simply be biased, for example insisting that, “…no major new field discoveries are expected.”  This before the Permian had been developed.  Or the argument in 2010, when the Marcellus was first being tested, that “The same financial fundamentals that have hurt other shale plays apply to the Marcellus: difficulty identifying core areas, high marginal costs to produce shale gas, poor economics, the play area is so large that a lot more capital will be destroyed than in other shale plays.”

Interestingly, many of the shale pessimists were also active in the peak oil movement, and just as those promoting that idea expressed great certainty about a very uncertain issue, so many shale pessimists have great faith in their pronouncements.  “It takes an enormous leap of faith to see shale oil production rising another 2 mbpd from here, along with several leaps of logic, which the Citigroup report had in abundance.”

The critic bragged about relying on “cold, hard facts” but in fact, shale production has risen by 4 mb/d since then, even after prices dropped below levels said to be necessary to maintain production.  Not bad for a report derided as “amateurish” which made “extremely dubious claims.” (The same pundit trashed myself and others as peak oil denialists a decade ago.)

I once remarked to a peak oil advocate who, describing the many challenges the industry faced, reminded me of Luke Skywalker, who had to be told by Yoda, “Always with you it cannot be done.”  At some point, the pessimists need to explain how the industry has, by their view, defied gravity for well over a decade, continually increasing production as if a dozen pundits had not predicted otherwise (to paraphrase Charles Mackay’s description of the Thames refusal to comply with the London astrologers’ flood warning).

   Hirsch, Robert “The Inevitable Peaking of World Oil Production.”  In:  Bulletin, Atlantic Council of the United States, October 2005.


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While the media is often focused on how multibillions are being poured into energy transition projects worldwide (usually focusing on solar and wind), global oil and gas is busy wooing financial investors--some of which seem wary to stay linked to hydrocarbon projects. The potential problem will not bet be related to a lack of investments in renewables but the reduced availability of available financing for existing and future oil and gas projects. The influx of cash into U.S. shale oil and gas may be hiding the real situation on the ground, which may be bleaker than we realize.

Conventional oil and gas projects are lacking mainstream finance options it seems, countering the prevailing media reporting about the majors' high-profile multibillions in profits and increased dividends for shareholders. The media reporting about Shell’s decision to handout more than $125 billion to its shareholders during the next couple of years, which has made headlines, is distracting focus from the situation of the majority of the smaller operators and oilfield service companies.

The total oil and gas sector is far from out of the woods, as debts have become a real burden for many companies. When looking at the offshore sector, the situation has become dire. Debts are staggering, while investments in offshore upstream projects have been faltering. The latter has resulted in a severe liquidity crunch, hitting offshore drillers and oilfield services companies. The latter situation has been discussed at a oil and gas conference in Oslo, Norway recently, where offshore bankers painted a dire picture. Hit by high debt levels and low dayrates for vessels and rigs, companies are struggling to refinance operations. At the same time, the current volatility in the oil and gas markets has constrained major investments into offshore developments during the last few years. The only current bright spots are in the Arabian Gulf, the Red Sea and East Mediterranean.

Offshore service companies such as Seadrill, Solstad Offshore and DOF are still worried about the future, as the market's slow recovery has not yet resulted in better financing options. Globally, analysts are not expecting a real improvement before 2021. The main issue for most service companies is debt being too high, which could result in restructuring or even bankruptcy. As Bloomberg reported earlier this month, “the global offshore drilling outlook remains bleak, with contract coverage expected to be below 55 percent for the rest of 2019, amid a net rig supply increase of 54 rigs year-to-date.”

Some companies have been able to get loans lately, but the majority are still hunting for cash. With institutional investors and banks mainly looking at developments in the U.S., it may be time to restructure or re-educate financial advisors too. The future may not revolve around U.S. shale and gas, as investments there are going to be very high risk. At the same time, U.S. operators are already struggling to meet their debt reduction goals. Some relief has come from the OPEC+ oil price strategy, but the debt is still suffocating.

Western capital discipline is now a potential threat. If banks are not willing to provide adequate financing, operators increasingly will have to look for alternative financing options. The latter could also lead to a fire sale of assets or companies to incumbents from other regions. Looking at the current developments in the Middle East, North Africa and Africa, it would not come as a surprise if Arab investment funds or “private” oilfield service companies are going to hunt for opportunities that emerge in the West. Some acquisitions have already have been made, but no major offshore oilfield services companies have been targeted yet. Looking at some of the key names in the space and their financial situations, it doesn’t take a rocket scientist to see the opportunity on the horizon.

Edited by ceo_energemsier

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US-led effort to limit IMO 2020 compliance would not cut fuel prices

US refiners, producers say they are ready for IMO 2020

White House reportedly had concerns about price spikes

EIA sees rule boosting Brent crude prices by $2.50/b



A US-led defection from next year's tougher international marine fuel sulfur standards would be difficult, if not impossible, and would not lead to lower domestic fuel prices, according to a study released Wednesday by a group of US oil and gas producers, refiners, shippers and trade unions.


Charles River Associates conducted the study for the Coalition for American Energy Security, which formed to lobby US lawmakers about the benefits of the International Maritime Organization's 0.5% global sulfur cap on marine fuels starting January 1, from the current 3.5%.

"The US is well positioned to support the global shift to lower sulfur marine fuels, both at the refinery and crude production levels," the study said. "Global refiners and shippers have had many years to prepare, and it appears the industries are driving toward a transition with minimal price disruption or fuel availability issues."

In October, the White House was reportedly considering ways to delay the rule on concerns that it would cause retail gasoline and diesel prices to spike in the middle of President Donald Trump's re-election campaign.

The Trump administration cannot likely delay the IMO rule at this point, but the study raises the possibility of a US-led effort to reduce global compliance.

S&P Global Platts Analytics sees the spec changes as the "most disruptive event to hit the refining sector in decades," requiring a major shift in the structure of global bunker fuels and initially displacing about 3 million b/d of HSFO. Analysts expect middle distillates cracks to surge and gasoline cracks to stay firm.


The Energy Information Administration expects the IMO rule to boost Brent crude prices by about $2.50/b as a result of higher demand for light sweet crudes. "However, EIA expects broader global crude oil market conditions to have more significant effects on Brent prices than IMO regulations," EIA said in a March report.

EIA sees US retail regular-grade gasoline prices averaging $2.67/gal in the first quarter of 2020 with diesel prices averaging $3.23/gal -- both up from the Q1 2019 averages of $2.36/gal for gasoline and $3.02/gal for diesel, according to the latest Short-Term Energy Outlook.

Rapidan Energy Group expects the IMO rules to "spark upheaval in the distillate market" and "possibly provoke political intervention from the Trump administration," it said in a note earlier this year.

The refiner-commissioned study said the IMO rules benefit countries that produce light sweet crudes, such as the US, while negatively affecting heavy sour producers like Saudi Arabia, Russia, Iraq, Iran, Venezuela and Canada.

"Therefore, the opposite can be said of a move to partial IMO [compliance], as the higher demand for HSFO and lower value of low sulfur fuels lead to a decrease in the value of US crude oil," the study said.

In April, 14 Republican US senators, including those from top oil and refining states Louisiana, Oklahoma and North Dakota, urged Trump to let the marine fuel sulfur standards take effect without interference, arguing that US refiners and the US trade balance both stand to benefit.

"Any attempt by the United States to reverse course on IMO 2020 could create market uncertainty, cause harm to the US energy industry, and potentially backfire on consumers," the senators said.

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This year, the U.S. will surpass Malaysia to become the world’s third largest seller of LNG. The country could even eclipse Qatar and Australia to take the top spot by 2024. This is truly staggering growth considering that LNG exports from the contiguous 48 just began in February 2016, when Cheniere Energy’s flagship Sabine Pass terminal in Louisiana first came online.

U.S. LNG has thus far reached over 30 nations, with South Korea, Mexico, Japan, and China receiving the most. By the end of 2019, the U.S. will have doubled its export facilities to six. And the country will have expanded its capacity to ~9 Bcf/d, more than 20 percent of current LNG demand. Although China has now put a 25 percent tariff on U.S. LNG, the expectation is that the trade war will eventually be worked out, reopening the door to the world’s most vital incremental customer.

For LNG buyers, the U.S. is a highly desirable partner. The country has soaring domestic gas production (up 60 percent since 2008), a massive low-cost resource base, flexible contracts, and a hub-based pricing system that reflects the transparency of supply and demand. IHS experts, for instance, estimate that the U.S. has 700 Tcf of gas that can be produced even when prices are below $3 per MMBtu. The EIA expects annual U.S. output to grow non-stop at 1-2 percent for decades to come, double the domestic consumption rate.

U.S. LNG is expanding the short-term, spot market, now accounting for just 30 percent of global trade. This is helping to increase flexibility and liquidity in the market, importantly giving the less wealthy nations a better chance to participate. While it still represents just 12-14 percent of global gas usage, LNG is the fastest growing traded commodity. Trade has been rising 8-10 percent per year in recent years and growth will remain in the 4-7 percent range for as far out as current modeling goes.  

As for U.S. gas users, LNG exports are a bullish factor and will put a floor under domestic prices. However, numerous studies indicate that a coming U.S. LNG export surge of 15-20 Bcf/d would likely only increase domestic prices 10-15 percent in the mid-term, and perhaps even less in the long-term. Exports will actually keep price increases in check because they beget more gas production. 

The comparison that some U.S. industrial groups make to Australia, where an LNG export boom led to domestic gas shortages and spiked prices, is a faulty one. Australia has been exporting over 60 percent of its production, while the U.S. should top out at below 20 percent. Australia has also crippled itself with bad policy, such as exploration and fracking bans. Ultimately, if U.S. LNG exports do increase domestic prices too much, they will simply limit themselves by pushing buyers to look for cheaper sellers. The U.S. also has a “protect the public interest” clause where the federal government can limit outside sales if deemed necessary.  

Nevertheless, the U.S. government and domestic gas users must constantly monitor developments. With so much LNG exports coming online, pioneer Cheniere says that Henry Hub-based contracts could account for ~35 percent of global LNG by 2025. In short, LNG exports will increasingly bring competition for American buyers and tie the U.S. to the more precarious globalizing market.  

To be sure, U.S. LNG faces substantial competition. While the Trump administration has been advertising to buyers in Europe, Russia says that its piped gas will remain at least 30 percent cheaper. And Gazprom has been surprisingly willing to renegotiate contracts to remain Europe’s primary supplier. Lowering transport costs, Australia is much closer to fast-growing Asia than the U.S., and Qatar is rapidly expanding its export capacity to retain its top ranking. Other emerging competition for U.S. LNG is Canada, Mozambique, European re-sellers, and giant commodity trading houses with wide international links.

Yet, the potential for all LNG sellers is great. Natural gas is increasingly the go-to fuel for nations to grow their economies, lower greenhouse gas emissions, and backup intermittent wind and solar power. In a carbon-constrained world, it is cleaner and more flexible natural gas that will continue to win out.

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The Exit Of U.S. Giant ExxonMobil Highlights The Decline Of North Sea Oil And Gas

It seems that the U.S. exodus of the Norwegian Continental Shelf (NCS) is now in full swing. Following hot on the heels of the decision by Chevron last year to exit the region, the news is coming out of Houston that the largest U.S. energy company, ExxonMobil, is planning to sell its Norwegian assets. Although they are no longer an operator in the region, the U.S. giant holds stakes in around 20 operating fields and projects in the area.

A continuing trend

Despite this being the most significant transaction on the NCS for a decade, Julien Mathonniere, global crude oil deputy editor at ICIS does not believe this deal will have a substantial impact on the region. "ExxonMobil sold its operated oil and gas assets in Norway two years ago and no longer is an active player in the Norwegian North Sea" he explained. "We're only talking of the remaining, non-operated Norwegian Continental Shelf assets here, which are sizeable but not huge. Norway's national oil company (NOC) Equinor already operates most of these fields."

Daniel Rogers, oil and gas analyst at GlobalData, agreed that the move will have little impact. "ExxonMobil's position in Norway has been dwindling over the recent years; the company offloaded all of its operated assets in the country in 2017 but still retains stakes in 19 producing fields," he said. “Norwegian production only accounts for approximately 3% of the company's total portfolio, and the sale could help focus on activities in more core growth regions such as onshore U.S. and deep-water South America."



Looking for low-cost oil

The strategy behind the decision is simple: oil economics are shifting to more profitable plays and areas for integrated oil companies like ExxonMobil. "The tentative merger between Chevron and Anadarko earlier this year has signaled a change of paradigm among majors, some of which are refocusing on the more profitable U.S. shale plays and LNG projects," Mathonniere added. "ExxonMobil is the largest U.S. oil and gas company, so if its competitor Chevron has identified profitable opportunities in U.S. shale and LNG, then I'm inclined to think that ExxonMobil will follow through in some way, especially since those opportunities are low-hanging fruits lying in its backyard."

The age of the independents

ExxonMobil's exit could pave the way for several smaller, independent operators with lower operating costs to enter the arena, in much the same manner as Chrysaor's acquisition of ConocoPhillips UKCS assets for $2.68 billion last year. Norway's Okea, a private equity-backed firm, has also been mentioned as a potential buyer, and independent exploration and production companies like Aker BP, DNO, Lundin Petroleum, and PGNiG could also be among the front runners for a potential bid.



"Aker BP and DNO both previously expressed interest for mature NCS assets," Mathonniere continued. "Both are Norwegian. DNO made a hostile and controversial $778.5 million bid for U.K.'s Faroe Petroleum in November 2018, eventually ending with 20% more shares of Faroe, for a total ownership of 30.6%. Aker BP acquired 11 NCS licenses from Total for $205 million in July 2018. Both seem well positioned to continue their asset spree."

Building a balanced portfolio

For potential buyers, the assets would provide a steady positive cash flow and an oil-weighted production portfolio. ExxonMobil's Norwegian production in 2018 averaged 155,000 barrels of oil equivalent per day and has declined year-on-year over the last 11 years due to production declines in major fields such as Statfjord, coupled with the sale of significant assets like Balder.

"With estimated remaining recoverable reserves of approximately 400 million barrels of oil equivalent from producing fields, there is significant value to be captured," Rogers continued. "Growth opportunities include the Trestakk oil field due to commence production in 2019 with expected gross recoverable reserves of 80 mmboe, the Snorre expansion project expected to extend field life beyond 2040 and gas discovery opportunities at Lavrans and Mikkel Sor."

A steady decline for the North Sea

The decision by ExxonMobil to leave the area also highlights the fact that the North Sea is not where the future of oil is. “It's been a declining petroleum province for a while, and it only accelerated after the oil price collapsed in late 2014," Mathonniere concluded. "Activity there has registered a painful decline, particularly concerning field investment expenditures, but also to operating costs.

"Exploration activities are below the levels that would allow renewing reserves. Production is hence not sustainable. The Johann Sverdrup is the latest big discovery on the NCS, but it might also be the last one given the lackluster exploration budgets."


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Regardless of what one says about shale, it sure has created and caused a lot of stir and a lot of sleepless nights and heartburn for too many globally. Russia from 2010s-2014 spent a lot of $$$ in EU and the US and maybe Canada too, to portray shale in a bad light and spread disinformation and create chaos because they were afraid of losing influence by losing market share to shale.


Shale Fight Makes OPEC Accept Lowest Market Share Since 1991






(Bloomberg) -- For almost three decades, OPEC has always pumped at least 30% of the world’s crude oil, creating an informal floor for Saudi Arabia and its allies in the cartel. The level has survived everything from wars and economic crises to terrorist attacks and diplomatic spats.

Yet, with OPEC set to extend output cuts for the rest of the year and potentially into early 2020, its share of the oil market is all but certain to drop below 30% for the first time since 1991, according to Bloomberg News calculations.

The sliding market share of the Organization of Petroleum Exporting Countries, which meets in Vienna on Monday, highlights how the cartel keeps giving ground to rising U.S. shale production in pursuit of higher prices.

“For Saudi Arabia, the oil policy right now is 100% revenues,” said Amrita Sen, chief analyst at consultant Energy Aspects Ltd. “But if inventories don’t fall and prices don’t rise, the policy is not sustainable.”

Saudi Arabia and Russia agreed on Saturday to push for an extension of the current OPEC+ production cuts for the rest of the year and potentially all the way to March 2020, making the outcome of next week’s gathering in Vienna of OPEC and non-OPEC oil ministers all but a foregone conclusion.

Bloomberg calculated OPEC’s market share by measuring crude production from the cartel -- which is subject to output caps -- but not condensates and other natural gas liquids that are excluded from the quotas. Monthly OPEC output was then measured against quarterly global oil demand as estimated by the International Energy Agency.

OPEC nations are bearing the burden of the market-share loss unevenly. Under U.S. sanctions, Tehran and Caracas have seen their production collapse, lightening the effort other members had to make to support high oil prices. Since December, Iranian and Venezuelan output has fallen by almost 1 million barrels a day, hitting its lowest level in about 40 years, according to Bloomberg News estimates.

Other OPEC nations have avoided trouble by simply flouting the rules, virtually pumping at will. Iraq, for example, produced 4.7 million barrels a day in May, matching a record it set in December.

But Saudi Arabia, the group’s most important member, is having to make deeper cuts than initially planned, reducing output recently to 9.7 million barrels a day, well below the level of 10.3 million a day it agreed with its OPEC partners.

The deeper Saudi cuts show Riyadh is willing to cross previous red lines. Khalid Al-Falih, the Saudi oil minister, said in a speech in 2017 that the kingdom wouldn’t fight a structural change in the market and “bear the burden of free riders,” warning it wouldn’t cut its output unilaterally.

But the loss of market share shouldn’t be a huge surprise. Ali Al-Naimi, the previous oil minister who ran Saudi oil policy for two decades, warned about the risk soon after his forced retirement. Al-Falih reversed Al-Naimi’s strategy of pump-at-will, designed to curtail the growth of shale production, opting instead to sacrifice market share to lift prices.

“Anybody who thinks he or any country is going to influence the price in today’s environment is out of his mind,” Al-Naimi told the Financial Times in 2016. “I have no idea why they want a reversal because a high price will definitely bring more crude to the market and OPEC will further lose [market] share.”

With oil-demand growth weakening due to the impact of the U.S.-China trade war and U.S. shale set to grow strongly in the second half of this year and beyond, Saudi Arabia and OPEC face the prospect of extending their cuts into next year or even 2021, deepening the loss of market share still further.

“At a minimum, OPEC has to sustain the present cuts through to the end of 2020,” said Simon Flowers, chairman of consultant Wood Mackenzie Ltd. “OPEC’s got a tricky job.”

It’s a lower-for-longer oil-production scenario that suggests that OPEC is aiming for a price that’s too high. Although Saudi Arabia shies away from price targets, it needs $70-$80 a barrel to meet the kingdom’s fiscal requirements. But by pursuing that price, it’s boosting not just shale, but also deepwater exploration.

According to the International Monetary Fund, Riyadh needs $85 a barrel to finance its budget, compared with an average of $78 during the 2000-2015 period.



So far, Riyadh has avoided a reckoning thanks to unusually high demand growth and the help of the American sanctions on Caracas and Tehran. But the longer the cartel keeps production cuts in place, the more evident it becomes that the strategy relies on strong demand, sanctions and outages. Take away one of those elements, and Riyadh will face a difficult choice: cut deep, or accept lower prices.

“OPEC’s balancing act gets harder in face of weak demand,” said Bassam Fattouh, head of the Oxford Institute for Energy Studies. “OPEC hopes that it does not have to confront this choice anytime soon, though this is beyond its control.”

Riyadh has signaled it would rather lose further market share than embark on another pump-at-will oil policy. Each time that the kingdom has shifted policy toward fighting for market share -- in 1986, 1998 and 2014 -- oil prices have collapsed.

For now, it has the support of Russia, with President Vladimir Putin announcing on Saturday that he’s agreed with Saudi Crown Prince Mohammed Bin Salman to extend the OPEC+ agreement.

Yet Moscow is starting to worry about the strategy. Since both countries came together in late 2016 to manage the oil market, they have privately disagreed about the ideal level for prices.

Putin brought the conflict into the open in early June, explaining that “there are some disagreements” between Moscow and Riyadh “that stem from a different understanding of what can be called a fair price.”

Putin went further: “Look at the price per barrel of oil that is used to calculate, say, the budget of Saudi Arabia. It is much higher than what we use. Ours is $40 per barrel, and their price is higher. That is why, of course, they want to keep the price higher.”

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US crude exports hit new high; more Permian crude expected in Gulf


US crude oil exports are expected to remain high moving forward as a new wave of Permian Basin crude oil hits the Gulf Coast in coming months.

Crude exports out of the US hit an all-time high of 3.77 million b/d in the week ended June 21, according to data released Wednesday from the Energy Information Administration, breaking the previous record high of 3.607 million b/d set during the week ended on February 15.

The latest record week was an increase of 350,000 b/d to the week ended June 14, which saw 3.422 million b/d exported, according to the EIA. Furthermore, last week marked the fifth consecutive week in a row at US crude exports exceeded 3 million b/d, which could become a new normal for export volumes.

The jump in exports and its rather steady level at or above 3 million b/d comes at a time when multiple pipeline projects are underway to bring more crude directly from the Permian to the Gulf Coast.

A collection of three new crude pipelines, including the EPIC interim crude line, are expected to start up between now and the end of the year. Together, the lines will have capacity to move an additional 2 million b/d of crude from the Permian Basin to the Gulf Coast.

Linefill on the 400,000 b/d EPIC line was expected to begin in late June, with anticipated startup in July. EPIC will move crude from the Permian Basin to Corpus, Christi, Texas.

Plains All American’s 670,000 b/d Cactus 2 pipeline also will move crude from the Permian to Corpus Christi and is expected to be operational in the third quarter.

Phillips 66’s Gray Oak, with connections to Corpus Christi, Sweeny and Houston is set to start in October, according to sources.

As Gulf Coast refinery demand for light sweet crude is at its maximum level, many of the additional barrels reaching the region will be exported, but in order to exported, the prices on the Gulf Coast must be appealing to international buyers.

“More pipelines coming on means more supply gets to the Gulf Coast with nowhere to go,” a broker said.

Pipelines out of the Permian currently carry more than 4 million b/d of crude to market, which is right around current Permian production of 4.1 million b/d. S&P Global Platts Analytics forecasts Permian production to reach roughly 5 million b/d by the first quarter 2020. With additional pipes coming online, however, there will be sufficient takeaway capacity in the Permian through 2020.

As more crude reaches the Gulf Coast there will be a growing need to increase storage and export infrastructure. Currently, 22 facilities across three Gulf Coast states have the ability to export nearly 6 million b/d, according the Platts data. And there are more projects in the works to meet growing demand. By 2021, Gulf Coast export capacity could reach over 10 million b/d.

For US crude barrels to find buyers on the international market, they must remain competitive and reactive to changes in arbitrages. This is exactly how values for US crude on the Gulf Coast have responded.

Despite large crude stock draws and increased refinery inputs and utilization in the USGC reported last week, which might typically be bullish for oil prices as it points to a decrease in supply, differentials for Gulf Coast grades have remained rather weak.

August barrels of West Texas Intermediate at the Magellan East Houston terminal were heard to trade Wednesday morning at their lowest level since October 23, at a $4.25/b premium to cash WTI. That is a dramatic decline in values. The 30-day rolling average for front-month MEH has been about $6.88/b.


Strong exports combined with high crude runs have reduced USGC crude inventories.

In the week ended June 21, PADD 3 stocks saw a 6.26 million-barrel draw, according to weekly data from the EIA. Moreover, in the week ending on June 14, PADD 3 stocks saw a 5.83 million-barrel draw, bringing the total draw over the past two weeks to over 12 million barrels, EIA data showed.

Net inputs into PADD 3 refineries increased by 280,000 b/d in the week ending on June 21 to just under 9.3 million b/d, according to EIA data. This increase in net inputs brought PADD 3 refinery utilization up 2.4% to 96.1%, the highest level since early January, EIA data showed.

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U.S. refinery capacity reaches record high at the start of 2019


As of January 1, 2019, U.S. operable atmospheric crude oil distillation capacity was a record-high 18.8 million barrels per calendar day (b/cd), an increase of 1.1% since the beginning of 2018, according to EIA’s annual Refinery Capacity Report. The previous high of 18.6 million b/cd was set at the beginning of 1981. U.S. annual operable crude oil distillation unit (CDU) capacity has increased slightly in six of the past seven years. Operable capacity includes both idle and operating capacity.

Refinery capacity is measured in two ways: barrels per calendar day and barrels per stream day. Barrels per calendar day reflect the input that a distillation unit can process in a 24-hour period under usual operating conditions, taking into account both planned and unplanned maintenance.

Barrels per stream day reflect the maximum number of barrels of input that a distillation facility can process within a 24-hour period when running at full capacity under optimal crude oil and product slate conditions with no allowance for downtime. Stream day capacity is typically about 6% higher than calendar day capacity.


Source: U.S. Energy Information Administration, Refinery Capacity Report

EIA’s Refinery Capacity Report also includes information about secondary refining units—downstream refinery units that process the products coming from the atmospheric crude oil distillation unit into ultra-low sulfur diesel, gasoline, and other petroleum products. Secondary refining capacity, including thermal cracking (coking), catalytic hydrocracking, and hydrotreating and desulfurization, increased by less than 1% from year-ago levels.

The number of operable refineries remained at 135 on January 1, 2019; however, similar to last year’s report, four refineries previously considered separate in survey data were merged into two. Tesoro Refining & Marketing’s Carson and Wilmington plants (now owned by Marathon) in California combined operations, and the Par Hawaii and Island Energy Services plants in Kapolei, Hawaii, also merged.

Targa Resources started up a new condensate splitter in Channelview, Texas, in 2019 that was idle at the start of the year but began operating during the first quarter. Suncor Energy split its reporting of the Commerce City East and West plants in Colorado.

Marathon Petroleum Corporation acquired 10 refineries from Andeavor in 2018, making it the largest refiner in the United States. Marathon’s refineries collectively have an operable capacity of slightly more than 3.0 million b/cd, 16% of total U.S. refining capacity and about 800,000 b/cd more capacity than the second-largest refiner, Valero Energy Corporation.

Refinery runs and crude oil production both continued at record levels in the United States in 2018. U.S. crude oil production, which averaged 11.0 million barrels per day (b/d) in 2018, has more than doubled since 2009. Crude oil inputs to refineries averaged 17.0 million b/d in 2018 compared with 14.3 million b/d in 2009.

Since 2009, operable refinery crude oil distillation capacity increased 1.2 million b/cd, and utilization rose from 83% in 2009 to 93% in 2018, resulting in the 2.6 million b/d increase in crude oil inputs. During the same period, U.S. crude oil imports decreased by 1.3 million b/d, and U.S. crude oil exports increased by 2.0 million b/d, leading to an overall decrease in net imports of 3.3 million b/d.


Source: U.S. Energy Information Administration, Refinery Capacity Report
Note: Differences between crude oil inputs and the sum of production and net imports reflect inventory changes and unaccounted for crude oil.

Note: Differences between crude oil inputs and the sum of production and net imports reflect inventory changes and unaccounted for crude oil.
EIA’s Refinery Capacity Report also includes information on capacity expansions planned for 2019. Based on information reported to EIA in the most recent update, U.S. refining capacity will not expand significantly during 2019. A June 21 fire at the 335,000 b/cd capacity Philadelphia Energy Solutions refinery complex, the largest refinery on the East Coast, has resulted in its announced closure.

Further investment in U.S. refinery expansion projects depends on expectations about crude oil price spreads, the characteristics of the crude oils produced, product specifications, and the relative economic advantage of the U.S. refining fleet compared with refineries in the rest of the world.

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Phillips 66's oil port off Corpus Christi aims to load 16 VLCCs a month

Competition heats up to move next wave of US exports

LOOP is currently only port able to fully load VLCCs

Platts Analytics sees 2020 exports of up to 4.5 million b/d


Phillips 66's proposed deepwater oil export terminal off Corpus Christi, Texas, expects to load up to 16 VLCCs a month, joining an already competitive market to move the next wave of US crude exports, according to its application the US Maritime Administration made public Monday.

The project, called Bluewater Texas Terminals, would have two single-point-mooring buoys able to handle two VLCCs at a time. Crude exports could flow onto the supertankers at a rate of 80,000 b/hour, or up to 1.9 million b/d, during a single-vessel loading.

US crude exports hit an all-time high of 3.8 million b/d in the week ended June 21, according to US Energy Information Administration data.

S&P Global Platts Analytics projects US crude exports will average 4 million-4.5 million b/d in 2020.

Phillips 66 spokesman Dennis Nuss said the company did not plan to share any additional information about Bluewater "as this project is not yet approved."

It is the third proposal for a VLCC-capable crude export terminal off Corpus Christi, after proposals by Trafigura-backed Texas Gulf Terminals, and a joint venture of the Port of Corpus Christi and The Carlyle Group.

Magellan Midstream Partners has also expressed interest in an export terminal off Corpus Christi, but has yet to announce any firm plans.

Nine deepwater oil ports have been proposed or considered across the Gulf Coast, including several off greater Houston, one off Brownsville, Texas, and one off southeastern Louisiana. Four of those have sought federal approval, a process expected to take at least a year.

The Louisiana Offshore Oil Port is currently the only US port able to fully load VLCCs and ultra large crude carriers without lightering from smaller vessels. LOOP started exporting US crude through VLCC in February 2018, almost 40 years after it opened as the only deepwater terminal for US oil imports.

While LOOP typically loads about one VLCC cargo a month for export, it turned around two cargoes in the same week in early June -- the New Prime, bound for India, and the Captain X Kyriakou, bound for South Korea.

Oil trader Trafigura said earlier this year that its Texas Gulf Terminal proposal would "complement, not replace, exports from other facilities," when asked if Corpus Christi could support more than one deepwater oil port.

"Having multiple projects reflects and reinforces the need for the significant infrastructure that will be needed to allow the export of US crude oil," spokeswoman Victoria Dix said.

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First delivered WTI Midland crude oil cargo trades in Platts assessment process


The development of a market for US crude delivered into Europe took a further step forward Tuesday with the first trade of a delivered WTI Midland cargo in the Platts Market on Close assessment process.


The trade followed a competitive offer of the grade by US oil producer Occidental Petroleum, which was reduced to Dated Brent plus 60 cents/b before being lifted by BP.

The offer was the first time that Occidental Petroleum has offered in the Platts MOC, although BP was a regular bidder in the process during the first quarter of 2019.

Occidental's offer was for a 700,000 barrel cargo loading from the MODA Ingleside Energy Center, with delivery expected between August 27-31.

Ingleside, owned by midstream company MODA, is an oil terminal in Corpus Christi, Texas. It was formerly owned by a subsidiary of Occidental until 2018 when it was sold to MODA.

The facility is currently capable of light-loading a VLCC and reverse lightering the remainder with a Suezmax. In the future, Occidental expects to be able to light-load a VLCC and fill the remainder with an Aframax.

The terminal receives WTI solely from the Plains All American Cactus Pipeline, which originates in the Permian Basin and terminates north of Corpus Christi.

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Amid record US crude exports, WTI Midland trades in London MOC


The development of a more transparent market for growing US crude exports into Europe took a further step forward this week with the first ever trade of a delivered WTI Midland cargo in the Platts Market on Close assessment process.

On Tuesday, BP lifted an offer from Permian producer Occidental Petroleum for 700,000 barrels of WTI Midland cargo at a 60 cents/b premium to Dated Brent in the Platts Market on Close assessment process.
The offer was the first time that Occidental Petroleum has offered in the Platts MOC, although BP was a regular bidder in the process during the first quarter of 2019.

On July 1, 2019, Platts started reflecting pipeline provenance in its DAP Europe WTI Midland assessment. The assessment reflects crude supplied via the BridgeTex, Cactus, Longhorn or Midland-ECHO pipelines.

Market participants in Europe Wednesday pointed to growing arrivals of US crude over the summer, citing a highly competitive environment with a swarm of discounted barrels from the Mediterranean and West Africa.

Sources talked of a “push arbitrage” from the US Gulf Coast, arguing that Europe is not short of deeply discounted crudes.

“Europe is certainly not pulling,” a trader said. “[It] is very much [the] US pushing.”

With US light sweet crude production growing, and exceeding US refinery demand for those barrels, and export capacity increasing, the international market is the only outlet for excess US barrels.

In recent weeks, Europe has taken about one-third of US crude exports compared with just under half of US crudes going to Asia.

S&P Global Platts cFlow data shows an estimated 7.1 million barrels of US crude heading to Europe the week ending June 28. That’s down slightly from 8.17 million barrels the week ending June 14, but would put total June crude exports to Europe at roughly 28 million barrels, up from the roughly 16.3 million barrels in June 2018 reported in US Energy Information Administration data.

However, with an abundance of discounted Mediterranean and West African crudes, some traders expected the flow from the US to slow down.

“Hard to see the US arbitrage to Europe working so well now for August loaders given the weaker CPC [Blend], weaker Dated [Brent], and weaker [West Africa], etc.” a second trader said, adding that the European market called for cheaper US crude.

“The US continues to price down to the level it takes to work into Europe, right now it feels very much like it’s still searching for homes so despite Europe not needing it or wanting it, I think it’s still going to come,” the first trader said.

US crudes have done well in Europe, largely because of advantaged pricing.

WTI Midland has set the floor for the DAP (delivered at place) Rotterdam market since Platts began publishing values for the grade back in September 2018.

Most recently, WTI Midland DAP Rotterdam discounts to rivals like Forties and Ekofisk have averaged $1.19/b and $1.37/b, respectively, over June.

US crudes like WTI also represent a great deal for European refiners in terms of refined product yields.

opr_20190704_us_ara_refiners.jpg opr_20190704_wti_midland_rotterdam.jpg

Platts data shows that WTI offers a European refiner better product yields than Forties, but worse yields than Ekofisk in the ARA or Azeri Light in the Mediterranean. Despite that, WTI continues to pour into both regions, as deep price discounts bolster refining margins.

Light Houston Sweet cracking margins in the ARA have outpaced cracking margins for Azeri Light, Ekofisk and Forties since April, Platts data shows.

There is only so much Ekofisk and Azeri Light to go around, and WTI has stepped in to fill a large gap left by suppliers like Iran and Libya, not to mention Urals most recently following contamination issues with that crude on Russia’s key Druzhba pipeline.

US crude production for the first time averaged over 12 million b/d in April, with over one third of that production coming from the Permian basin.

Furthermore, S&P Global Platts Analytics forecasts Permian production to reach 5 million b/d by Q1 2020, a level that would outstrip the current Permian pipeline takeaway capacity of around 4 million b/d.

A collection of three new crude pipelines, including the EPIC interim crude line, are expected to start up between now and the end of the year. Together, the lines will have capacity to move an additional 2 million b/d of crude from the Permian Basin to the Gulf Coast.

Linefill on the 400,000 b/d EPIC line was expected to begin in late June, with anticipated startup in July. EPIC will move crude from the Permian Basin to Corpus, Christi, Texas.

Plains All American’s 670,000 b/d Cactus 2 pipeline also will move crude from the Permian to Corpus Christi. Linefill has begun on Cactus 2 and market sources expect the pipeline to be operational starting in August.

Phillips 66’s Gray Oak, with connections to Corpus Christi, Sweeny and Houston is set to start in October, according to sources.

“More pipelines coming on means more supply gets to the Gulf Coast with nowhere to go,” a broker said.

As more Permian crude reaches the Gulf Coast, there will be a growing need to increase storage and export infrastructure. Currently, 22 facilities across three Gulf Coast states have the ability to export nearly 6 million b/d, according the Platts data, and there are more projects in the works to meet growing demand.

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How Texas is Making America More Energy Secure

Key Findings

The United States is now producing more oil and natural gas than any country in the world, and American oil and natural gas production volumes are at record highs.

The United States is poised to export more energy than it imports for the first time since the 1950s; during the past decade, the U.S. energy trade deficit fell by $363 billion, while the non-energy trade deficit rose by $343 billion.


Texas is leading America toward this unprecedented level of U.S. production and energy security.


The Lone Star State now accounts for 40% of U.S. oil production and 25% of our nation’s natural gas production


The Permian Basin recently overtook Saudi Arabia’s Ghawar as the world’s top producing oilfield and produces the second most natural gas of any field in the United States.


Texas’ Eagle Ford Shale is the second highest producing oilfield in the United States.


In January 2019, Texas monthly oil production was 900,000 barrels per day (b/d) higher than the previous January. That increase is greater than Oklahoma’s and Wyoming’s total monthly oil production, combined.


Driven by energy exports, Laredo surpassed Los Angeles as the nation’s top trade port in March of 2019.


Thanks to homegrown, low-cost natural gas, Texas residential consumers saved more than $7 billion over ten years.

Maintaining U.S. energy security – and the Texas energy revolution – will require more pipelines, expanded export infrastructure, and a stable regulatory environment.


Expanding the Houston Ship Channel has the potential to provide significant benefits to both energy exporters and other shippers.

New restrictions on pipelines and other infrastructure would create an unstable investment climate – and could ultimately undermine the Texas energy revolution.


Texas oil and natural gas development is an integral part of U.S. energy security. With unmatched levels of production coming from places like the Permian Basin and the Eagle Ford, the Lone Star State is providing the resources we need domestically, while also supplying our trading partners with a reliable source of affordable energy. Soaring production from Texas has also lowered petroleum’s share of the U.S. trade deficit to almost zero, as growing exports help to shift the country from a net importer to a net exporter. This transition means billions of dollars in revenue, an improved balance of trade and a substantially decreased reliance on foreign countries for our energy needs.
For this energy revolution to continue, however, it’s crucial that the build-out of pipelines and export infrastructure continues. Doing so will mean continued job growth and improved positioning for Texas within the global energy market. But this infrastructure expansion is not possible without a stable regulatory environment. While Texas has proven the ideal location for energy development with its pro-business and low-tax environment, adding burdensome regulations would have dire consequences on production and the Texas economy.
Texas is known around the world for its prolific energy production, and as global demand for oil and natural gas increases in the coming decades, the Lone Star State is well-positioned to capitalize on that opportunity – helping to make America even more energy secure in the process.
Edited by ceo_energemsier

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exans for Natural Gas report examines how Texas oil and gas production protects America – and what it will need to keep doing so

Texas oil and natural gas production is critical for strengthening American energy security, according to a new report from Texans for Natural Gas. The report details how Texas energy is driving American energy production, less dependent on foreign imports, and America’s historic transformation into a net energy exporter. 

The report, Leading the Charge: How Texas is Making America More Energy Secure, also outlines what steps Texas must take to remain the driving force behind American energy security. 


  • Texas is breaking energy production records: The Permian Basin recently overtook Saudi Arabia’s Ghawar as world’s top producing oilfield and produces the second most natural gas of any field in the United States.
  • Reducing the trade deficit: According to the U.S. Census Bureau, petroleum has dropped from 66 percent of the U.S. trade deficit in April 2011 to just 2.1 percent in December 2018.
  • Exporting powerhouse: Driven by energy exports, Laredo surpassed Los Angeles as the nation’s top trade port in March of 2019. Also, the value of Texas monthly crude exports increased by over 1,780 percent in just three years from January 2016 to January 2019.
  • American manufacturing renaissance: The petrochemical manufacturing sector in Texas has seen $69 billion in new capital investment since 2010 and employs an estimated 878,000 people.

“The Texas-led shale revolution is cutting America’s trade deficit and generating billions of dollars in economic benefits for our state and the rest of the country,” said Steve Everley, spokesperson for Texans for Natural Gas. “For decades politicians have promised us energy security and a rebirth of manufacturing. Fracking in Texas has delivered both.”

As production continues - crude oil output from the Permian Basin is expected to double to 8 million b/d in only four years – new pipelines and other infrastructure will be critical to keeping the Texas energy boom alive. The new report also highlights how Texas will need to expand ports and keep a stable regulatory framework. 

“Our energy security depends on the continuation of the Texas miracle,” Everley added. “The enormous benefits afforded by Texas production will be lost if we don’t have the necessary infrastructure and stable regulatory environment to facilitate continued growth.”


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‘Don’t get used to it’: OPEC’s free pass for US shale will be short-lived, JP Morgan says

A gradual fall in oil prices over the coming years could prompt Saudi Arabia and OPEC to reclaim some of its market share from the U.S., according to the head of EMEA oil and gas research at J.P. Morgan.

Saudi Arabia and OPEC are “there to support oil while they are effectively pregnant with all this economic growth and capital they have got to deliver. But, having said that, what we are saying to the bulls is: Don’t get used to it,” J.P. Morgan’s Christyan Malek told CNBC’s “Squawk Box Europe” on Thursday.

Earlier this week, OPEC and 10 other allied producing partners agreed to keep 1.2 million barrels a day off the market for another nine months.

The energy alliance, sometimes referred to as OPEC+, has been reducing output since 2017 as part of a sustained bid to prop up crude prices.

The Middle East-dominated group has succeeded in keeping crude futures near $60 a barrel, albeit five years after oil prices last traded above $100. But, a protracted period of production cuts has seen its share of the global oil market sink to the lowest level in almost three decades.

Meanwhile, the U.S. shale industry has expanded at such a rapid rate that it threatens to overwhelm OPEC-led efforts to mitigate demand concerns, swamping the global oil market with supply.

When asked whether he believed OPEC kingpin Saudi Arabia could change this dynamic and eventually outlast the U.S. shale industry, Malek replied: “I think, at the moment, with OPEC and Saudi focusing on fiscal (and) economic policy, they are absolutely two feet in the value camp.”

“This value proposition, the fact they are giving shale a free pass so to speak is short-lived… I mean three of four years ago, who would have thought that they would be happy with $60 to $70?”

“The bar keeps falling, it is just very gradual. In a few years’ time I expect $50 to be an okay oil price, at which point that could see Saudi and OPEC reclaim that market share and then it becomes more competitive,” Malek said.

‘Peak, plateau and then decline’
International benchmark Brent crude traded at around $63.80 Thursday morning, little changed from the previous session, while U.S. West Texas Intermediate (WTI) stood at $57.13, down almost 0.4%.

Speaking to reporters in Vienna, Austria earlier this week, Saudi Energy Minister Khalid al Falih said shale would eventually go the same way as every other basin in history.

It will “peak, plateau and then decline,” Al Falih said, before adding: “Until it does I think it is prudent … to keep adjusting to it.”
Source: CNBC

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