Wonders of Shale - Gas, bringing investments and jobs to the US

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On 5/21/2019 at 12:50 PM, wrs said:

Do you consider third tier companies as representative of the industry?

A separate Wall Street Journal survey from last year of the 30 largest shale producers found a combined $1.7 billion in profits in 2017, after the group burned through $50 billion in losses over the previous five years and over $100 billion in losses over the last 10 years. In reality there is a bifurcated market of companies in distress and other companies doing better.

As Bloomberg noted, this year’s best-performing stock in the oil sector is Hess Corp., which doesn’t have any operations in the Permian.

The drilling boom has been made possible by rock-bottom interest rates and a wave of finance from Wall Street. But with years of capital going up in smoke, it’s not clear how long Wall Street will stomach the losses. The industry is inching closer to positive cash flow, and may in fact reach that goal this year.

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INEOS announces €2.7B investment in new European Chemical Complex

Today INEOS has approved a €2.7 billion capital project to build both a world scale ethane cracker and a PDH (Propane Dehydrogenation) unit in Northern Europe. Both units will benefit from US shale gas economics.

This will be the first new cracker built in Europe for two decades. It will also be one of the most efficient and environmentally friendly plants of its type in the world.

The location of the site will be determined soon and it is likely to be on the coast of North West Europe. A project team has been assigned to consider options and the project is expected to be completed within four years.

Gerd Franken, Chairman INEOS Olefins and Polymers North says, “This new project will increase INEOS self-sufficiency in all key olefin products and give further support to our derivatives business and polymer plants in Europe. All our assets will benefit from our ability to import competitive raw materials from the USA and the rest of the world”

This new investment follows a decision taken by INEOS last year to increase the capacity of its existing crackers.

Jim Ratcliffe adds, “INEOS is going from strength to strength. This new investment builds on the huge investment we made in bringing US shale gas to Europe and will ensure the long-term future of our European chemical plants.”

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The next most likely takeover target in the Permian right now is Endeavor Energy Resources, according to Wood Mackenzie (WoodMac).

“The storied Permian producer has been on the radar for months as an attractive buy for Shell,” WoodMac said in a company statement.

“Endeavor's huge 350,000-acre position in the Midland Basin is fiercely desired, and it’s the biggest private company in the area,” WoodMac added.

The second most likely Permian takeover target currently is Diamondback Energy, according to WoodMac, which described the company as “a powerful force ripe for acquisition”. By WoodMac’s models, Diamondback Energy could grow production by nearly 100 percent in the next five years.

The third most likely takeover target in the Permian at the moment is Concho Resources, WoodMac revealed. Concho could also grow its output close to 100 percent within five years and its well metrics “look fantastic”, according to WoodMac, which said any major buying the company would catapult themselves to be a Permian “powerhouse”.

WoodMac, which said it’s guaranteed the “race leader” will change “a few times”, insists that more mergers are coming in the region.

“The gaps amongst the majors' Permian outlooks aren't sustainable. There are huge G&A mismatches with smaller companies that need to be resolved too. Other companies are 'all in' on the Permian but have inventory issues,” WoodMac stated.

The company added that M&A over the past year was about “shared lease lines” but said “following Oxy's lead, it may now pivot back to rock quality and scale”.

 The OXY deal, which is for $59 in cash and 0.2934 shares of Oxy common stock per share of Anadarko common stock, is valued at $57 billion, including the assumption of Anadarko’s debt.

WoodMac is an energy research and consultancy company which traces its roots back to 1923. The business has locations all over the world.

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ExxonMobil announces major expansions

Announcements of expansions in both plant footprints and polymer capacity have been pouring in of late, as both resin producers and chemical manufacturers charge ahead to meet increasing demand. ExxonMobil is the latest to make two separate announcements.

The first is the $2-billion Baytown, TX, chemical plant expansion project that is projected to create approximately 2,000 new jobs during construction.

The Baytown expansion is in addition to the company’s Growing the Gulf, an initiative launched in 2017 that outlined plans to build and expand manufacturing facilities along the U.S. Gulf Coast, creating more than 45,000 high-paying jobs across the region.

“Our substantial investments in the United States support ExxonMobil’s long-term growth plans and will result in more high-paying jobs,” said Darren W. Woods, ExxonMobil Chairman and CEO. “Through the billions of dollars that we’re investing in the Permian Basin to increase oil production and the expansion at our operations along the Gulf Coast, our company is making significant lasting contributions to the U.S. economy and the many communities where we operate,” said Woods.

The company’s Baytown chemical expansion will allow ExxonMobil to “maximize the value of increased Permian Basin production” and deliver high-demand, high-value products “at the company’s Gulf Coast refining and chemical facilities.”

The expansion, expected to start up in 2022, includes a new Vistamaxx performance polymer unit, which produces materials that offer higher levels of elasticity, softness and flexibility. The new unit will produce about 400,000 tons of Vistamaxx polymers a year.

The project also will enable ExxonMobil to enter the linear alpha olefins market, a polymer used in numerous applications including polyethylene plastic for packaging. The new unit will produce about 350,000 tons of linear alpha olefins a year.

In a second announcement, ExxonMobil said it has completed an expansion of its specialty elastomers manufacturing plant in Newport, Wales, which doubles the plant’s manufacturing capacity and increases global manufacturing capacity of Santoprene thermoplastic elastomers by 25%.

“ExxonMobil’s high-performance plastics help make automotive products lighter, resulting in improved fuel efficiency and higher performance, compared with products made with traditional materials,” said Karen McKee, President of ExxonMobil Chemical Co. “This Newport investment doubles the site’s manufacturing capacity of higher-value products.”

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Freeport LNG expansion gets quick DOE signoff on exports


Approval adds 0.72 Bcf/d for export to non-FTA nations

Less than two weeks after FERC signoff


Continuing its recent pattern of quick-turnaround approvals, the Department of Energy has approved 0.72 Bcf/d of LNG exports from an expansion at the Freeport LNG project in Texas to nations that lack free-trade agreements with the US.

The approval, covering a 20-year period, comes less than two weeks after the US Federal Energy Regulatory Commission gave its nod May 16 for a fourth train at the facility on Quintana Island, near Freeport, Texas.

It marks another step forward for an expansion project among the second wave of US LNG projects seeking to capture LNG demand in the early to mid-2020s.

With the issuance of the order, DOE has authorized a total of 32.99 Bcf/d of natural gas for exports to non-FTA countries, the department said in its order Tuesday. To reach its public interest determination, it relied in part on its 2018 study, considering export volumes of up to 52.8 Bcf/d of natural gas, that found the US would see net economic benefits from exports of domestically produced LNG.

The addition of Train 4 would add over 5 million mt/year of LNG to the existing project, raising the Freeport facility's total export capability to over 20 million mt/year, Freeport noted in a statement.

Train 4 operations are anticipated to commence in 2023. The first train at Freeport is scheduled to begin commercial operations in Q3 2019, with the full three-train operation expected by mid-2020. The project hit a delay caused in part by flooding following Hurricane Harvey in 2017. About 13.5 million mt/year of capacity has been contracted under 20-year agreements, according to Freeport.


DOE in its order said it has not found an adequate basis to conclude that the Train 4 project would be inconsistent with the public interest. The order noted that DOE would cautiously monitor market conditions going forward, as it receives successive applications for LNG exports.

Energy Secretary Rick Perry recently has sounded more bullish about the importance of prompt LNG export approvals. In testimony before Congress May 9, he said DOE has not under his watch denied export applications and "if I'm still the secretary will not," given the immensity of US supply of natural gas.

DOE officials equated natural gas exports with spreading liberty and advancing energy security for allies, in statements released Tuesday.

"I am pleased that the Department of Energy is doing what it can to promote an efficient regulatory system that allows for molecules of US freedom to be exported to the world," said DOE Assistant Secretary for Fossil Energy Steven Winberg. DOE Undersecretary Mark Menezes said the increased export capacity from Freeport LNG "is critical to spreading freedom gas throughout the world by giving America's allies a diverse and affordable source of clean energy."

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Texas crude oil production continues to break records in 2019. This comes in spite of declines in rig count, drilling permits, well completions and E&P employment, according to the Texas Alliance of Energy Producers’ Texas Petro Index.

The Texas Petro Index (TPI), a monthly measure of growth rates and cycles in the Texas upstream oil and gas economy based on rig count, drilling permits, well completions and employment, declined in 1Q 2019.

“Typically, these E&P indicators decline during an observable, sustained contraction in oil and gas activity, but that doesn’t appear to be what we’re seeing now,” said Karr Ingham, petroleum economist for the Texas Alliance of Energy Producers and creator of the TPI. “I do think these decreases can partly – even largely – be attributed to the sharp and unexpected fourth quarter 2018 crude oil price declines, but clearly there are other forces at work. These have become increasingly evident over the course of the current recovery and expansion from the 2014-2016 industry downturn.”

Part of this explanation comes from efficiencies by Texas oil and gas producers, with daily production exceeding five million barrels for the first time, according to Alliance estimates. Essentially, operators are making it happen with fewer resources.

After cyclically peaking in December 2018, direct upstream employment is waning – to the tune of about 3,500 job losses from December to March 2019. Further, the March estimate is down by more than 70,000 compared to the all-time peak employment total in December 2014.

Industry employment and crude oil production estimates in March suggest that for every one direct upstream oil and gas employee, about 700 barrels of oil are produced, compared to about 170 barrels per employee in 2009.

“Given current price levels, which continue to improve, the Texas upstream oil and gas economy remains in expansion mode,” said Ingham. “But the nature of oil and gas economic growth in Texas is different in 2019 largely because it has become perfectly apparent that Texas oil and gas companies can produce more crude oil with fewer resources deployed.”

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New Study: ‘Independent’ Oil, Gas Operators Drive American Energy Development By Wide Margin

Independent oil and natural gas producers are dominating the United States energy markets, according to a new study commissioned by the Independent Petroleum Association of America. Independent oil companies now accounting for 83%  of the nation’s oil production and 90% of its natural gas and natural gas liquids (NGL) production, according to “The Economic Contribution of Independent Operators in the United States,” which also finds that independent producers develop 91% of the nation’s natural gas and oil wells.

Independent natural gas and oil producers are defined as those companies that typically do not have midstream or refining operations, unlike the much-larger “major” or “international” oil companies. The report looked at more than 2,200 companies, and the direct, indirect and induced jobs created through their upstream activities. The report also provides state-level analysis, including production, well count and operating expenses by state.

The study, conducted by the business analytics group IHS Markit, also describes the economic contribution of independent oil and natural gas operators in the United States – up to $573 billion or 2.8% of U.S. GDP in 2018 and expected to rise to $823 billion or 3% of U.S. GDP by 2025.

Oil, natural gas and NGL production, as well as drilling and operations were analyzed for 2016, 2017 and 2018, and were forecast for 2020 and 2025.
Other key findings from the report:

    •    Through their business, supported 4.5 million American jobs in 2018;
    •    From 2016 to 2025, capital investment by independent companies is projected to increase by 87%, and;
    •    Independent producers will continue to drive solid contributions to the U.S. economy over the remainder of the study period (2025) and, quite likely, beyond.
“Independents continue to play a major role in America’s natural gas and oil industry. Their entrepreneurial spirit and willingness to take on risk spawns innovation – like opening up shale plays – while creating jobs and contributing to U.S. gross domestic product (GDP),” said IPAA President and CEO Barry Russell, in a statement. With these companies making up 90% of U.S. natural gas activity, their production is a critical component in supporting regional and local economies, maintaining strong national security and the effort to tackle global climate change with improved technology and efficiency.”

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Natural Gas is the Green New Deal

Last month, America observed the 50th anniversary of the unofficial holiday known as Earth Day.

Good Samaritans cleaned beaches, picked up trash from highways, and marched peaceably in many cities in support of battling climate change — mainly by reducing our consumption of fossil fuels. But a major milestone went unmentioned on Earth Day, namely that America’s greenhouse gas emissions, or GHGs, are lower today than they were 20 years ago even as the economy has expanded by more than half.

How was this accomplished? Not as a result of environmental regulations and mandates or the huge subsidies given to renewables like wind and solar, but rather by using more, not less, of a fossil fuel called natural gas.

It’s a well-known fact that natural gas burns a lot cleaner than coal or oil. The simple chemical composition of the gas lends itself to fewer impurities in combustion, and because it burns cleanly, carbon dioxide emissions are less than half that of coal and a third less than fuel oil, diesel or gasoline.

At the same time, thanks to the so-called “shale revolution,” natural gas is abundant and inexpensive, and likely to remain so for the foreseeable future.

Consequently, the power-generation sector, which is responsible for about 25 percent of GHGs in the U.S., has moved quickly to adopt natural gas. Electric utilities have shuttered more than 250 coal plants since 2010, and a dozen more will close this year.

A decade ago, coal-fired generation accounted for about 50 percent of the electrons coursing through the nation’s power grids, but by last year, that had dropped to 27 percent. No utility in the nation has plans to build a new coal plant in the future.

Opponents of fossil fuels acknowledge that gas has a smaller carbon footprint than coal but nonetheless object to its use because of the methane releases associated with its production and transportation. Because the heat-trapping characteristics of methane are 20 times greater than carbon dioxide, environmentalists have good reason to be concerned.

However, again they fail to acknowledge the tremendous progress that has been made in recent years to contain methane emissions.

According to data from the Environmental Protection Agency and the Energy Information Administration, methane emissions from onshore U.S. oil and natural gas production fell 24 percent between 2011 and 2017 even as production increased by almost 50 percent and 730,000 miles of new transmission and distribution pipelines were added.

What’s more, the Oil and Gas Climate Initiative, a coalition of global energy companies, has committed to cutting average methane intensity by at least 20 percent and total emission levels by one-third by 2025.

America’s natural gas boom is also helping reduce greenhouse gas emissions abroad. From virtually zero a few years ago, liquefied natural gas, or LNG, exports approached 800 billion cubic feet last year. With capacity expected to double by the end of this year, export volumes will continue to grow exponentially. Indeed, by 2024 the U.S. is projected to be the world’s second-largest exporter of LNG, after Qatar.

Countries such as China, India and Japan that still rely heavily on coal for power generation are among the largest purchasers of American LNG. To the degree they substitute our “clean gas” for their domestic or imported “dirty coal,” the air becomes cleaner while global greenhouse gas emissions are reduced.

Cheap natural gas, made available by hydraulic fracturing, has already made the U.S. the world leader in carbon emissions reduction.

Though President Donald Trump took us out of the Paris climate treaty, we will surely exceed the carbon reduction targets in that agreement, and well ahead of schedule.

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Marathon Oil Completes Kurdistan Exit As US Shale Focus Grows

Marathon Oil Corp. continues to narrow its focus on U.S. shale with the completion of its Kurdistan divestiture on May 31.

The transaction, which represented a complete country exit for the Houston-based company, included Marathon’s 15% participating interest in the Atrush Block in Kurdistan. Production from the assets averaged 2,400 net barrels of oil equivalent per day (boe/d), 100% oil, during the first quarter.

Both the buyer of the assets and the terms of the transaction were not disclosed. Marathon had previously announced the sale during its second-quarter results last year. The company originally had expected to close the transaction by year-end 2018.


Siemens Enters Permian Gas Processing Market With Electric Compression Technology

Siemens was awarded a contract to provide three residue compression trains for two, 250 million (500 million total) standard cubic feet per day (MMscf/d) cryogenic gas plants in the Delaware Basin on May 30.

Each train consists of a 22,000 horsepower motor, gearbox, and multistage Dresser-Rand DATUM centrifugal compressor, all mounted onto a single skid. The compressors, motors, and drives will all be built by Siemens in the U.S. and is scheduled for commissioning the latter part of 2020.

Mid-size gas treatment plants traditionally use reciprocating compressors driven by electric motors or gas engines. However, with the increase in production from shale plays, larger gas plants—in the range of 200 to 300 MMscf/d—are being constructed, forcing gas processing companies to consider alternative compression solutions in order to reduce costs, footprint, and maintenance.

While the traditional approach would require 10 large reciprocating units for this project, Siemens’ centrifugal compressor solution met the entire plant duty for this 500 MMscf/d project using just three compression units while ensuring low turndown capability. The plot space and the ancillary infrastructure—such as foundations, piping, wiring, cabling and electrical systems—was also remarkably reduced resulting in significant capital cost savings for the customer.

The high efficiency of the DATUM compressors, coupled with their easy maintenance, was a major factor for selecting this configuration. With a DATUM fleet availability of more than 99.7%, the plant will have minimum downtime despite the un-spared compressor configuration and will ensure minimal loss of production, bringing significant value to the customer in meeting contractual production guarantees.

“This project is an excellent example of Siemens’ ability to offer its customers a complete integrated solution,” Patrice Laporte, vice president of Oil and Gas for Siemens America, said.

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Big oil’s investments in Permian pay off as earnings soar

Big Oil is starting to see its billions worth of investments in the Permian Basin pay off as production soared and the fourth quarter of 2018 brought higher-than-expected profits.

Chevron Corp., one of the biggest producers in the region, as well as Exxon Mobil and Royal Dutch Shell, all reported higher profits thanks to the increased flow of oil out of West Texas.

These oil majors were mocked for nearly missing the shale revolution when they lost out to faster-moving independents a few years ago, but in the years since, they’ve purchased hundreds of thousands of acres in West Texas, investing billions in land, rigs and drilling programs.


Chevron pumped 2.93 million barrels per day in 2018, the highest ever annual production in the company’s history, and Exxon’s production crested 4 million barrels a day for the first time in almost two years.


In the Permian Basin alone, Chevron saw its annual production jump 71 percent last year, hitting 310,000 million barrels per a day annually.


Shell, while significantly behind Chevron in terms of Permian production, still saw its production hit 145,000 barrels of oil equivalent per a day in the region, a 200 percent increase compared to January 2017, the Anglo-Dutch major said. As for Exxon, its Permian production soared 90 percent from the same time last year in the fourth quarter.


“The growth they’ve been able to achieve in terms of their Permian output is pretty spectacular,” said Lysle Brinker, director of equity and energy research IHS Markit. “They still might not be as good as executing in unconventional plays (as independent companies), but they've gotten a lot better,” he said, noting well completions, drilling and efficiency.

With deep pockets to develop technologies and snatch up additional acreage, plus strong relationships with service companies, majors will see the Permian become in an even bigger part of their portfolios, Brinker said.

“We think there’s going to be more consolidating in the Permian and the big guys could be bigger players,” Brinker said.

Majors also can benefit from integration of Permian output into their refining and downstream portfolios. Recent announcements speak to that trend: Chevron purchased a Pasadena refinery to process lighter crude; Exxon Mobil has plans to increase output at its Beaumont refinery by 65 percent amid a $20 billion plan to grow its manufacturing on the Gulf Coast; and Shell recently started up an expanded petrochemicals complex in Louisiana.


With U.S. oil production 23 years ahead of schedule, the majors are retrofitting Gulf Coast refineries to better process the lighter grade crude of the Permian, instead of the heavier crudes of Canada and Mexico, and expanding petrochemical operations to take advantage of relatively cheap natural gas production in West Texas.


Exxon CEO Darren Woods said on the company’s fourth quarter earnings call that investments in Texas refineries are really "a transportation play" to take advantage of Permian crude.

"We believe our approach will deliver the lower cost supply and give us a significant advantage," he told investors in the fourth quarter earnings call.



The integration of its manufacturing and midstream businesses in North America helped to partially offset lower refining margins across the company. Overall refining earnings climbed 73 percent the fourth quarter, reaching $2.7 billion from $1.56 billion the same time last year.

The Irving oil major said Friday that fourth quarter net income slipped to $6 billion, down from $8.3 billion the same time last year. But strong production in the Permian Basin and healthy refining earnings helped bump up its annual net income to $20.8 billion compared to $19.7 billion the year earlier, a 5.5 percent increase.

Woods signaled plans for Exxon to boost its capital spending and asset sales next year. Exxon plans to spend $30 billion on capital projects this year, a 16 percent increase from 2018.

Chevron said Friday that it earned $3.7 billion in the fourth quarter, up from $3.1 billion during the same period in 2017, and beat analyst expectations. Its full-year profits leaped more than 60 percent, to $14.8 billion, from $9.1 billion in 2017.


Chevron added 1.46 billion barrels of oil reserves in 2018, with the largest additions in the Permian Basin and LNG projects in Australia.


Chevron CEO Michael Wirth said he’s pleased with the company’s position in West Texas, particularly with regards to the company’s land and oil reserves. Chevron claims over 2 million acres in West Texas — it transacted over 150,000 acres of that between 2017 and 2018 — and the company has an estimated 11. 2 billion barrels of oil-equivalent reserves in the region. Wirth said he expects their oil reserves to continue to increase in the Permian.

Chevron expects to spend 3.6 billion in capital and exploratory expenditures in the region this year.


Shell, while not as big of a player as Exxon or Chevron, is on the hunt for more Permian Basin acreage. Shell is said to be eyeing a purchase of Endeavor Energy, which controls drilling rights on more than 300,000 acres of mostly undeveloped land in the Permian Basin in Texas and New Mexico, according to media reports.

Shell saw full-year profits jumped 36 percent to $21.4 billion in 2018. Stronger performance in the fourth quarter was driven by higher oil and gas prices, year-on-year, as well as a stronger contribution from liquefied natural gas (LNG) trading, the oil major said.


ConocoPhillips, while under-represented in the Permian, also beat expectations this quarter. The company plans to ramp up U.S. shale production this year. CEO Ryan Lance said on the fourth quarter earnings call that he sees a 25 percent increase in U.S. shale growth for ConocoPhillips this year driven by improvements in technology.


Bloomberg Intelligence energy analysts Fernando Valle and Jonathan Mardini wrote in a note that they believe ConocoPhillips, a $75 billion company that they call the “poster child” of financial discipline, will look to expand activities in the Permian this year.,

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South Africa's Sasol says 2nd unit at LCCP starts production


(Reuters) - South African petrochemicals firm Sasol Ltd said on Monday that a second unit at its U.S. ethane cracker project came online last week.

The company’s Lake Charles Chemicals Project (LCCP), which will convert natural gas into plastics ingredient ethylene, said the plant started producing ethylene oxide on May 31.

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U.S. crude output rises 2.1% in March to near record high: EIA


U.S. crude oil production rose 241,000 barrels per day (bpd), or 2.1 percent, in March to 11.905 million bpd, just below its record high, the Energy Information Administration (EIA) said in its monthly 914 production report on Friday.

That monthly increase in U.S. production from a revised 11.664 million bpd in February followed two months of declines in January and February. U.S. monthly output peaked at 11.966 million bpd in December.

Most of the increase came from the federal offshore Gulf of Mexico, which rose 11.1% to 1.907 million bpd, and North Dakota, which gained 3.2% to 1.352 million bpd.


Output in Texas, the biggest oil producing state, meanwhile, eased 0.1 percent to 4.873 million bpd.

Meanwhile, monthly gross natural gas production in the Lower 48 U.S. states rose to a fresh record high 99.3 billion cubic feet per day (bcfd) in March from the prior high of 99.1 bcfd in February, according to the report.

Those gains were driven by an 8.7% rise in the Gulf of Mexico to 2.9 bcfd and a 7.2% increase in North Dakota to a record high 2.8 bcfd.


In Texas, the biggest gas producing state, output declined 0.9% to 26.4 bcfd from a monthly record high 26.6 bcfd in February.

In Pennsylvania, the second-biggest gas-producing state, output rose 0.7% to a record high 18.8 bcfd.

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Aberdeen-headquartered energy service firm Centurion Group said today that it had bought a Texan valve technology company.

The swoop for Totalfrac is Centurion’s fourth acquisition in the last year and further cements the group’s position in the Permian basin, the heart of the US fracking industry.

Centurion recently announced the extension of its banking facilities to support its future growth plans, and expects to make further progress in 2019, both organically and by through acquisitions.

Totalfrac provides low maintenance, durable valves used in various well fracking and production operations.

To further support this acquisition, Centurion has invested in a fleet of wellhead isolation tools.

Centurion chief executive Fernando Assing said: “I am delighted to welcome Totalfrac to Centurion and look forward to working with them.

“Drilling, completions and production services are of critical importance to us, and for our customers, and we are pleased to be able to expand, and enhance, our flowback and well testing product lines.”

Derek Elzner, president of Centurion US land, said: “We are excited to announce the addition of Totalfrac to Centurion.

“The addition of their high-quality valves, designed to be low maintenance, will provide higher uptime for clients.

“This is yet another example of Centurion’s strategy to diversify product and service offerings, while providing our customers the highest quality products”.

Centurion Group employs about 1,200 people around the world, of whom 300 are based in Scotland.

In 2018 the group reported revenue increasing by 40% to £350 million and profits more than doubling to £56m.


The group has three business segments: accommodation and modular solutions,
drilling, completions and production, and infrastructure.

It operates across four key geographical markets: US land, Canada rentals and services, Canada infrastructure, and rest of the world.

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completed crude oil pipeline capacity additions by region

Source: U.S. Energy Information Administration liquids pipeline projects database

EIA recently launched a new liquids pipeline projects database that tracks more than 200 crude oil, hydrocarbon gas liquids (HGL), and petroleum products pipeline projects. Rising domestic crude oil production has led to several changes in Gulf Coast crude oil supply and demand patterns, creating a need for more pipeline capacity. Crude oil pipeline capacity additions originating in the Gulf Coast region represent most of the scheduled pipeline capacity growth over the next few years. EIA's new database provides an improved capability to track this growth.

The database contains project information such as project type, start dates, capacity, mileage, and geographic information for historical pipeline projects (completed since 2010) and future pipeline projects. The information in the database is based on the latest public information from company documents, government filings, and trade press, and it does not reflect EIA's assumptions on the likelihood or timing of project completion.

Gulf Coast region crude oil production, trade, and movements
Source: U.S. Energy Information Administration, Petroleum Supply Monthly

U.S. crude oil production doubled between 2010 and 2018, with about 70% of that growth coming from the Gulf Coast region. U.S. Gulf Coast crude oil production grew from 5.2 million barrels per day (b/d) in 2014 to 7.1 million b/d in 2018, driven by production in the Permian Basin in western Texas and southeastern New Mexico.

As U.S. crude oil production increased, imports dropped off significantly. Previously, Gulf Coast crude imports were shipped to refineries in the region, and they also moved north by pipeline to refineries in the Midwest. But as import volumes declined, less pipeline capacity was needed from the Gulf Coast to the Midwest. New pipelines and reversals of existing pipelines originating in the Midwest are increasingly moving crude oil south from the Bakken region in Montana and North Dakota, as well as from Canada, to the Gulf Coast. As a result, the Gulf Coast transitioned from being a net shipper to a net recipient of crude oil from elsewhere in the country in 2015.

More recently, increasing Permian crude production has outpaced pipeline takeaway capacity to bring the crude oil to market. The increasing crude oil production and need for more pipeline transportation capacity prompted a large expansion of crude oil pipeline infrastructure. In the region, nine intrastate crude oil pipeline projects have been announced or are under construction with in-service dates between 2019–2021. These projects are planned to move crude oil throughout Texas and Louisiana to further alleviate regional constraints.

EIA will update the liquids pipeline projects database twice a year, at the end of May and November (data will be vintaged to the end of April and October, respectively). Projects will be added or modified depending on best available information. The liquids pipeline projects database complements EIA's natural gas pipeline projects table.


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Exterran lands major water contract with Permian producer

Exterran Corp., a global systems and process company offering solutions in the oil, gas, water and power markets, announces its Water Solutions business has secured a significant produced water treatment contract with a major operator in the Midland area of the Permian basin.

The 30,000 barrels of water-per-day (bwpd) treatment system includes the removal of oil-in-water, suspended solids and iron. Offered as a turnkey package, the provided solution also includes accessories, manpower, and remote monitoring and reporting of water treatment data.

The contract follows a successful three-

month pilot in late 2018, where Exterran met or exceeded oil-in-water, suspended solids and iron outlet performance levels.

Todd Kirk, director of water at Exterran, said: “Over the past two decades, we have had many successful produced water operations around the world in over a dozen countries. These include a wide range of unique solutions designed to help meet any customer need from small mobile units that are lightweight, easy to ship, install and start-up to handling over a million bwpd of produced water at large processing facilities.

“Customers appreciate our expertise, efficiency and operational excellence. By partnering with a turnkey produced water specialist like Exterran, operators not only get a reliable portfolio of technologies, but also a team of experts to solve their water challenges and support them at a moment’s notice. Facility simplification, data acquisition, AI and experienced technicians help to solve manpower limitations in the basin and improve operations efficiency.”  

Exterran offers operators a full range of primary, secondary and tertiary treatment solutions for removing oil, contaminants and suspended solids from produced water. The company designs, builds, and operates systems that quickly, efficiently, and cost-effectively treat produced water ranging in volumes from 100 to in excess of 1,000,000 bwpd. 

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Cheniere, Apache sign historic Permian shale LNG deal


Cheniere Energy and Apache Corp. have signed a first-of-its-kind agreement on liquified natural gas. Through a newly announced, 15-year deal, Apache will produce and supply LNG to Cheniere Corpus Christi Liquefaction Stage III LLC, a subsidiary of Cheniere Energy Inc. The LNG price paid to Apache will be based on global LNG indices.

According to Cheniere, Apache has agreed to sell 140,000 MMBtu per day of natural gas to the Corpus Christi facility.

“This first-of-its-kind long-term agreement with Apache represents a commercial evolution in the U.S. LNG industry, as it will ensure the continued reliable delivery of natural gas to Cheniere from one of the premier producers in the Permian Basin,” said Jack Fusco, president and CEO of the gas company, adding that the deal will give Apache flow assurance on its gas.


The Corpus Christi Stage III project is being developed to include up to seven midscale liquefaction trains with a total expected nominal production capacity of approximately 9.5 mtpa. Corpus Christi Stage III received a positive Environmental Assessment from the Federal Energy Regulatory Commission in March 2019 and is expected to receive all remaining necessary regulatory approvals for the project by the end of 2019.

Last week, Apache signed a deal with Altus Midstream to handle other portions of its shale gas.

John Christmann, Apache’s CEO and President, said the agreement was made to leverage Apache’s Permian Basin asset scale and diversify its customer base.

Cheniere has one of the largest liquefaction platforms in the world, consisting of the Sabine Pass and Corpus Christi liquefaction facilities on the U.S. Gulf Coast, with expected aggregate adjusted nominal production capacity of up to approximately 45 million tons per annum of LNG operating or under construction.

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Altus bolsters Permian gas midstream foothold with pipe, plants

Altus Midstream is positioning itself for a long-term presence in the Permian Basin shale gas scene. This week the company bought into a long-haul pipeline plan designed to move more than 2 billion Bcf/d of natural gas from the Waha area in West Texas to the Texas Gulf Coast.

Through its 27 percent interest in the Permian Highway Pipeline, Altus will invest roughly $161 million in the project that it expects to be complete in 2020.

“This is a high-quality project supported by take-or-pay contracts with creditworthy counterparties,” said Clay Bretches, CEO and president.

Altus also announced this week that it has brought the first of three cryogenic gas processing facilites online in the Waha area. The

news should be welcomed by Apache Corp., who earlier this year had to shut down some gas production in the region of Altus' new cryogenic processing facility due to the lack of takeaway options and the price for gas. 

"These cryogenic processing facilities feature state-of-the-art SRX processing technology, which optimizes processing economics with better NGL recoveries in both ethane recovery and rejection mode versus more commonly used processing methods in the Permian Basin. Better recoveries will drive enhanced netbacks for Apache and provide a competitive advantage to Altus for third-party business," Bretches said.

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Sasol starts up second unit at Louisiana petchem complex


Sasol Ltd. has commissioned the second of seven production units scheduled to come online as part of its long-planned Lake Charles Chemicals Project (LCCP), an integrated ethane cracker and downstream derivatives complex under construction in Westlake, La., near Lake Charles

As of May 31, both portions of the complex’s combined ethylene oxide-ethylene glycol (EO-EG) are in operation, Sasol said.

Start-up of the EO-EG plant follows commissioning of the complex’s first production unit—the linear low-density polyethylene (LLDPE) unit—earlier this year


By the end of March, construction progress stood at 89%, with overall project completion at 96% and a capital expenditure amounting to $11.4 billion, the operator said.

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

• Ethane cracker: July.

• LDPE unit: August.

• Zeigler alcohols unit: November.

• Guerbet alcohols unit: February 2020.

• Ethoxylation unit: December.

Alongside its 1.5 million-tonne/year ethane cracker, LCCP will include six downstream chemical plants, including:

• Two large polymers plants capable of produced a combined 900,000 tpy of low-density (LDPE) and LLDPE.

• A 300,000-tpy EO-EG plant.

• A 100,000-tpy exthoxylation unit.

• A 173,000-tpy Ziegler alcohols plant, which will include a 30,000-tpy Guerbet alcohols unit and 30,000-tpy alumina unit.

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Total SA has agreed to take over Toshiba’s portfolio of LNG, including a 20-year tolling agreement for 2.2 million tonnes/year of LNG from Freeport LNG Train 3 in Texas and the corresponding gas transportation agreements on the pipelines feeding the terminal. Train 3 is expected to start commercial operations by second-quarter 2020.

Under the transaction, Total will acquire all shares of Toshiba America LNG for $15 million to be paid by Total to Toshiba and will be assigned all contracts related to the LNG business by Toshiba Energy Systems and Solutions Corp. for a consideration of $815 million to be paid by Toshiba to Total.

Total will therefore receive from Toshiba a net cash consideration of $800 million.

The takeover is in line with Total’s strategy to become a major LNG portfolio player, said Philippe Sauquet, president gas, renewables, and power at Total. “Already an integrated player in the US gas market, Total is set to become one of the leading US LNG exporters by 2020 with a 7 million-tpy portfolio,” he said.

The transaction is expected to close by yearend.

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PTT Global Chemical taps Bechtel for possible Utica Shale ethane cracker

Marcellus, Utica could support four more crackers: DOE

Sequential cracker projects could more easily draw workers

Appalachian gas producers, under pressure from prices below $3/Mcf, got a boost Thursday with engineering giant Bechtel's announcement that Thailand's PTT Global Chemical had awarded it a contract to build an ethane cracker in Belmont County, Ohio, in the heart of the Utica Shale.


The project still needs a final investment decision. But selecting Bechtel as the contractor of the project is a major step toward that decision. Bechtel Oil, Gas & Chemicals Senior Project Manager of Pennsylvania Chemicals Paul Marsden, already working as the manager of Bechtel's work on Royal Dutch Shell subsidiary Shell Chemical Appalachia's multibillion-dollar ethane cracker in Monaca, Pennsylvania, made the announcement at the Northeast Petrochemical Conference in Pittsburgh.

Another new cracker would give producers a new outlet for ethane, a natural gas liquid that they blend in the gas stream when it cannot be sold. The project is expected to be capable of producing 1.5 million metric tons per year of ethylene and its derivatives. Shell's plant will produce up to 1.6 million mt/year of polyethylene. Analysts speculated full capex for the project could reach $6 billion.

Charlie Schliebs, managing director of private equity funds at Stones Pier Capital, said the lack of a final investment decision announcement at this stage is to be expected. "These things [FIDs] take a long time, but that project is happening," Schliebs said.

The US Department of Energy has estimated that the Marcellus and Utica shales can support up to four more crackers, besides PTT's and Shell's. Observers expected a final investment on PTT Global's project more than a year ago. PTT Global could have been watching to see if costs on Shell's project spiraled out of control.

Asked whether Bechtel would face challenges getting enough labor to work on both the Shell project and the PTT, Marsden said it would be "a challenge. We will have to manage that." But he noted that the timing of the projects could actually work in the builder's favor, as having sequential projects lined up could encourage welders and other key workers to relocate to the region instead of simply coming in for one project at a time.

NGLs, which sell at prices linked to crude oil, are becoming a larger share of the revenues of Appalachian shale gas drillers. Producers see NGL production as the only escape from stable, low natural gas prices. Two Appalachian producers, Range Resources and Antero Resources, are already shipping ethane, propane and butane to Europe via Sunoco Pipeline's Mariner East family of pipelines.

PTT Global's US subsidiary, PTTGC America, is using the site of a shuttered FirstEnergy coal-fired power plant in Mead Township of Belmont County as the future cracker's site. The company has already allocated $100 million on surveys and permits.

Belmont County is the leading gas-producing county in Ohio with 2.6 Bcf/d of production in the first quarter, according to Ohio's Department of Natural Resources.

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Chevron Phillips Chemical Co. (CP Chem) has offered to acquire Nova Chemicals Corp. for more than $15 billion including debt, Reuters reported Thursday afternoon, citing unnamed sources.

UAE-based Mubadala Investment Co. owns Nova, which is headquartered in Calgary, and operates seven manufacturing sites in Canada and the United States. CP Chem boasts facilities in the Americas, Asia and Europe. According to Wood Mackenzie, the merger would elevate CP Chem’s status in the North American polyethylene (PE) segment.

“With this acquisition, Chevron Phillips would become the third-largest polyethylene producer in North America, just after Exxon Mobil Chemical Co. and Dow Chemical Co,” Wood Mackenzie Chemicals Principal Analyst Ashish Chitalia said in a written statement

Chitalia added that the deal would make CP Chem North America’s largest producer of high-density PE (HDPE), followed by LyondellBasell.

“There are synergies between both companies in the polyethylene and polystyrene sector,” continued Chitalia. “CP Chem is a predominant producer of HDPE, while Nova Chemicals’ portfolio leans toward linear low polyethylene (LLDPE).”

A combined CP Chem-Nova company would boast approximately 8.5 million metric tonnes per annum (mmtpa) of PE capacity, with HDPE accounting for 5.8 mmtpa and LLDPE just under 2.5 mmtpa, noted Chitalia. In North America, it would hold 20 percent of the total PE capacity share and approximately 25 percent of the HDPE capacity share, he added.

“In terms of styrenics, CP Chem is a major North American producer of polystyrenes through its American Styrenics JV,” continued Chitalia. “American Styrenic accounts for around 28 percent of North American polystyrene capacity. Nova Chemicals, on the other hand, is a major producer of expandable polystyrene with a capacity share of 22 percent in the region.”

Acquiring Nova would boost CP Chem’s ethylene merchant exposure, noted Chitalia.

“After the recent ethylene capacity increase at Cedar Bayou, Texas, CP Chem was exposed to 500,000 tonnes of ethylene to the merchant market, while Nova, post its acquisition of Williams Geismar (a cracker in Louisiana) is exposed to approximately 1 million tonnes of ethylene,” he said. “Together, the companies would have ethylene volumes equivalent of a world-scale cracker size of 1.5 million tonnes.”

Other highlights of a CP Chem-Nova merger that Chitalia pointed out include:

  • Each firm offers a technological edge, with CP Chem pioneering and licensing HDPE slurry loop technology and Nova licensing solution LLDPE technology.
  • CP Chem’s on-purpose and full-range alpha olefins capacities would complement Nova’s considerable exposure to comonomer alpha olefins for regional LLDPE production.

Chitalia also observed that the deal would enable CP Chem parent companies Chevron and Phillips 66 to diversify further in a consolidating petrochemical market while boosting their competitiveness and market reach.

“North American ethane feedstock advantage makes the region an ideal location for acquisitions/expansions in the ethylene-polyethylene sector,” Chitalia said.

Chitalia added that a CP Chem-Nova merger “would confirm the trend of Big Oil diversifying further into downstream,” with the firms treating petchems as an engine for growth and a conduit for securing margins.

“But CP Chem and Nova Chemicals also complement in terms of products (PE, polystyrene), geographic footprint and technology,” he concluded. “With up to  1.5 million of merchant ethylene available to CP Chem post-Nova Chemicals acquisition, the company would be in a strong position to leverage the second expansion wave on the Gulf Coast.”

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