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

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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US LPG exports set to climb

Renewed LPG demand growth in India and China will lead to growth of US exports later this year, according to ESAI Energy’s newly published Global NGL Outlook. Since exports have bumped up against capacity constraints, the timely completion of new LPG export terminals in the US and Canada will be vital to this export growth. Stronger demand has implications for propane and butane prices, whose discounts to naphtha have widened considerably.

As the year 2019 progresses, strengthening demand in India and China will lead to higher US LPG exports, according to ESAI Energy’s 12-month outlook.

As the report describes, Indian demand growth has already emerged from its 2018 slump. Annual demand growth in that country will jump to 60,000 b/d after falling to a 5-year low in 2018. Given that the country’s supply will barely grow this year, imports will be needed to meet almost all the new demand.

Demand in China, until recently the locomotive of global demand, fell in the second half of 2018 and barely changed so far in 2019. Following in India’s footsteps, the near-term commissioning of PDH and NGL-fed ethylene units in China will to lead to renewed growth in that country.

“Due to the US-China trade dispute, China will import more LPG from Middle East and Asian sources,” explains ESAI Energy Head of NGLs Andrew Reed. “However, there will be greater demand for US product to swap into other Asian markets as non-US product is swapped into the Chinese market. Between bullish Asian demand and new LPG terminals in Western Canada and the US Gulf Coast that eliminate export bottlenecks, developments will provide a boost to Mont Belvieu propane and butane prices.”

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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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Make all of the charts you want, I see trains pulling oil tank cars like there is no tomorrow.  There is demand for oil, all of it.  If nobody wanted oil, there would be none, nada, nothing, no oil.

Demand is what makes the market, supply can be there, beanie babies, tulips, covered wagons, but if there is no demand, price means nothing.

Hence, the market, demand rules, not supply.

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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.

US LNG EXPORTS ARE 'FREEDOM GAS': DOE OFFICIAL

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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What will happen if this comes true and drops further?

It will be a blood bath in the shale patch and it will be a clean up operation after that, the weak and sick will be gone and bigger , better operators with better quality rocks, better fiscal discipline and better economics will survive and thrive!

https://www.cnbc.com/2019/05/28/crude-could-drop-to-52-as-global-pressures-persist-top-technician.html

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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.”

 

https://www.ipaa.org/wp-content/uploads/2019/05/IPAA-Economic-Contribution-Final-Report.pdf

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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.

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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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Is the Shale Revolution Here to Stay?

Critics of the U.S. shale industry question its staying power.

 

Summary

U.S. shale oil is a booming business. As it drives up global oil supply and puts downward pressure on oil prices, U.S. production of shale oil poses a geopolitical threat to other oil-producing states. But critics say that the boom won’t last. If true, that changes the geopolitical calculus.

How much longer will shale oil be a booming business? The answer to that question, while fuzzy, has long-term geopolitical implications. U.S. shale oil production has grown steadily, putting downward pressure on the global price of oil. We’ve written before about the power of shale oil and the impact it has on other geopolitically important oil producers like Russia and Saudi Arabia, which rely heavily on oil revenue to either fund their government spending or support their economies. Our forecasts for these countries are built in part on the assumption that, as the global supply of oil increases, its price will hit a ceiling that could strain these countries’ public finances, which in turn would have political ramifications. But shale skeptics maintain that the industry is not sustainable. If they’re right, and if the shale industry were to die out in the next couple of years, tanking oil supply and spiking oil prices, the geopolitical calculus for Russia and Saudi Arabia would change substantially.

The critics’ argument is threefold. First, they claim that the shale boom depended on huge amounts of debt that was doled out without serious consideration for whether shale producers would be able to pay it back. Second, critics are worried that there’s less shale oil available than originally believed, reflected in shale wells’ depletion rates. Third, they see limited room for growth in the profitability of shale production as shale’s break-even price has stagnated. Combine these factors, the critics say, and you get an industry that will not endure. This Deep Dive will take a closer look at these criticisms and explore whether, in fact, U.S. shale really is an economically sustainable industry.

Shale: A Primer

To understand the criticisms of the industry, it’s important to understand what shale is and how oil is extracted from it – a technically complex and expensive process. Shale rock, embedded thousands of feet under the Earth’s surface, is less permeable than other types of rock. And yet it’s here that shale oil, or “tight oil,” is found. The extraction process for this oil is known as hydraulic fracturing – or “fracking” – and it requires drilling down to the shale deposits, and then drilling horizontally through the rock. The drillers then inject a water-based solution at high velocity to break apart the rock, creating fissures through which oil can flow. (This process can also be used to extract natural gas from shale deposits.)Fracking_Process.png

(click to enlarge)

The U.S. shale industry really took off in 2009. Thanks to the United States’ extensive shale formations, it has benefited hugely from the shale revolution. The combined technologies of hydraulic fracturing and horizontal drilling vastly increased the productivity of shale wells, and overall U.S. oil production has increased apace. In 2018, the U.S. produced an average of nearly 11 million barrels per day of crude oil, almost 60 percent of which came from shale. It’s helped the U.S. surpass Russia and Saudi Arabia in the production of hydrocarbons and is pushing the U.S. toward becoming a net energy exporter, a benchmark it’s expected to reach next year.

Financing: The Catalyst

Financing was, in many ways, the engine that drove the rise of shale oil, but the industry’s reliance on debt has also threatened to bring it down. In the wake of the 2008 financial crisis, interest rates fell, making debt cheaper and borrowing easier. In the low-interest rate environment, investors were looking everywhere for yield. Shale looked particularly appealing for debt investors since reserves could be used as collateral – if companies failed to pay their debts, the banks could simply take control of the reserves. This created the appearance of added security.

The availability of cheap, accessible debt coincided with two other important moments that created a turning point: skyrocketing oil prices and technological developments that had made the economics of shale drilling viable (though still expensive). Shale production took off, reversing a decadeslong decline in U.S. oil production that had begun in the 1970s.

Debt, however, is a double-edged sword. In exchange for immediate access to capital, firms assume higher operating costs down the road. This can lead to firms becoming over-leveraged as they assume so much debt that they cannot afford to both pay off the debt and pay regular operating expenses. So when oil prices tanked in 2015-16, many over-leveraged companies went out of business, causing U.S. oil production to drop from about 9.4 million bpd in 2015 to 8.8 million bpd in 2016. Notably, this was not an accident. Global oil supply had been climbing thanks to shale production. When supply is too high, OPEC typically cuts production to drive prices back up. But in 2015-16, OPEC chose not to cut supply, hoping that low prices would drive shale producers out of business and thus allow OPEC countries to reclaim market share they had lost to shale.

This downturn threatened to prove right concerns that, without high oil prices and access to cheap, plentiful debt, shale is not an economically viable industry. Companies had taken on unsustainable amounts of debt to fuel growth. When interest rates began to climb, the need to service that debt was a further incentive for shale companies to continue production – even if operations were barely or not at all profitable. These firms’ lending used to set up new wells created debt service expenses, which led to total operating expenses exceeding cash coming in from operations for too long; if interest rates had continued to rise, the entire industry would be, if not sunk, at least forced to slow production. This was not lost on debt investors, who of course feared that bankruptcies would wipe out most of their investment. As oil prices fell, access to debt capital decreased, forcing cash-strapped shale companies to turn instead to equity financing (that is, to issue more stock).US_Shale_Financing.png

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Bankruptcies did, in fact, increase substantially when oil prices plummeted in 2015-16. Banks, as they are wont to do, had offered loans based on current or recent conditions, without consideration for what would happen when oil prices dropped – an inevitability in a cyclical industry like oil. Meanwhile, larger companies bought up the assets of the smaller, less efficient ones, leading to industry consolidation.

But the cycle continued, despite OPEC’s best efforts to keep prices down long enough to destroy the shale industry, and conditions improved. As a number of companies went bankrupt, oil supplies decreased, and prices rose once again. The companies that survived were forced to cut their capital expenditures, which actually led to an improvement in cash flow. Since 2016, bankruptcies have declined significantly.US_Oil_Bankruptcy.png

(click to enlarge)

Still, some industry observers continued to insist that the economics of the industry itself – not just of individual companies – were fundamentally unsustainable because they relied too heavily on debt. They claimed that debt was not just one factor in shale’s growth but in fact the decisive factor. Without it, they said, the industry couldn’t survive, because total expenses, including debt services fees, would continue to exceed revenue. Since 2016, however, shale drillers have moved toward positive, or at least neutral, cash flow. As of early 2018, a greater share of shale companies was beginning to cover the cost of new wells with operating cash flow, rather than debt. Rystad Energy, an oil and gas market research firm, anticipates that in 2019 shale drillers will generate enough cash to cover capital expenses and pay dividends, though just barely.US_Oil_CashFlowBarrel.png

(click to enlarge)

If shale companies have enough cash remaining to pay dividends – even just a little bit – it’s a sign that they have enough cash on hand to better pay their debts. As of the fourth quarter of 2018, about 40 percent of companies in a 33-company sample of shale producers were cash-flow positive. To be economically viable, more companies will need to at least break even – in the case of shale, that means they need to generate enough cash from operations to cover their operating expenses without external capital.US_Oil_CapexCashFlow.png

 (click to enlarge)

So, while a good number of shale companies do seem to be in precarious financial situations, many are trending toward positive cash flow. And just because some companies are at risk of going out of business doesn’t mean that shale oil production will cease. Truly cash-strapped companies can sell their assets to major international oil companies that have diversified revenue streams and can keep shale machinery offline until oil prices rise. In other words, as time goes on, the shale industry will mature and, like any industry, experience both bankruptcies and consolidation as some companies prove to be more efficient operators than others.

Oil Reserves: Estimating What’s Out There

But it’s not just financing that shale skeptics criticize. They’re concerned, too, that shale companies substantially overestimated their reserves. They’re not wrong; many oil companies have had to revise their total reserve estimates downward, and it seems their initial overestimations were directly related to the question of financing. If companies had higher reserves – a form of collateral – they could take on more of the debt they needed to get underway. Similarly, when debt financing dried up in 2015-16 and companies started to issue stock, they overestimated their reserves so that it would be easier to raise money from investors.

How were oil companies able to convince banks and investors that their oil reserves were larger than they actually were? Oil-producing companies in the U.S. are required to file with the Securities and Exchange Commission estimates of their “total proven oil reserves” – the reserves for which there is a 90 percent chance that the oil will be recovered. But as the fledgling shale industry was starting to raise money, companies began to use a metric called “estimated ultimate recovery” instead. EUR simply refers to existing reserves, without indicating the likelihood of recovery. The metric is also based on the assumption that, as time goes on, companies would be able to replicate their early success – that additional wells would produce as much as already tapped wells. In retrospect, this was flawed logic; the initial wells are almost always the most productive ones. Shale drillers also assumed they could pack shale wells close together. But packed too tightly, the wells would pull from shared reserves, decreasing the amount that each could draw. Both assumptions contributed to overly optimistic EUR numbers.

In response, investors are now scrutinizing shale producers’ claims. They began by questioning shale companies’ estimates of their reserves – and therefore whether they were worth investing in – and have started pushing for greater accountability in firms’ capital expenditures and demanding higher returns. As a result, shale companies are now exercising more oversight of capital expenditures, cutting spending, moving toward positive cash flow, and using that cash flow to return dividends to investors or to buy back shares. All of this is bolstering the economic sustainability of the industry.

Shale producers’ estimates affect more than just financing. Market research firms and the U.S. Energy Information Administration (which is responsible for collecting and reporting economic data on the energy industry that is used in policymaking and economic forecasting) take into consideration the reserve estimates that companies put out. Historically, forecasts of U.S. shale oil production have been outstripped by actual production, and current forecasts are almost uniformly positive – the EIA and industry consulting firms Rystad Energy and Wood Mackenzie all anticipate substantial increases in oil production over the next 10 years, even with lower oil prices. That’s good news for the shale industry – even with more conservative estimates of their reserves, shale oil isn’t going anywhere.US_Oil_ProductionForecasts.png

 (click to enlarge)

The industry also stands to benefit from pipelines scheduled to come online in late 2019 and early 2020. Production has been constrained by a lack of transportation infrastructure in the U.S., and these pipelines will facilitate transport of resources from the Permian Basin, the source of nearly one-third of U.S. oil output, to refineries and export centers in places like the Gulf Coast. It seems shale oil production will continue growing, though at a somewhat slower pace than the industry initially anticipated.Global_Oil_Reserves.png

(click to enlarge)

Supply and Profitability: The Geopolitical Question

Ultimately, what affects geopolitics is not the durability of one shale company or another – it is the price of oil and whether the supply of oil continues to increase. And even if the growth in U.S. shale oil production slows, the industry will likely persist for at least the next decade. Skeptics have questioned the shale industry’s ability to sustain high levels of production since it took off over a decade ago. But U.S. production has often outperformed forecasts, and we have to keep this in mind when examining claims that the shale industry is not financially viable.

One of the primary concerns here is the industry’s profitability. As the industry has grown and matured, the break-even price per well has come down. But some doubters claim that there are fewer gains to be made through technological advances. If true, this would mean that the break-even point will not come down much further, leaving little room for growth in the profitability of shale. This may be a valid criticism. But that still puts the profitable oil price for a lot of shale companies well below Saudi Arabia’s fiscal break-even point (the point at which the government can balance its budget), which the International Monetary Fund says is currently about $80-$85 per barrel.US_Oil_BreakevenPrice.png

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Another, more convincing critique examines the relationship between long-term supply and profitability. It’s based on comparing production rates in the Bakken Formation and the Eagle Ford Group, some of the earliest shale basins to be tapped, with the Permian Basin, whose development only took off in 2013. The U.S. has seen net oil production gains since 2016, and much of those gains were from new wells, especially in the Permian Basin. Meanwhile, however, production in Bakken and Eagle Ford has declined following the 2015-16 downturn. (Eagle Ford has stagnated, while Bakken has only recently inched above its pre-2015 production levels.)US_Oil_Basins.png

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Since Eagle Ford and Bakken are older discoveries than the Permian, critics suggest that the former are more representative of what shale basins will be capable of producing after several years of drilling, and that those production levels will be much lower than following the initial discovery, when only the choicest wells were being drilled. The Permian’s production has an outsize effect on total U.S. production. If it follows the trend of its predecessors, that effect would be problematic.US_Oil_Regional_Production.png

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New wells usually produce more oil at the outset, and the rate at which oil flows thereafter is called the decline rate. The Permian’s decline rates are rising faster than expected. Take, for example, Wolfcamp – one of the drilling areas within the Permian Basin. When drilling in the Permian got underway in 2013, observers expected decline rates of 5-10 percent; but Wolfcamp’s rate is now closer to 15 percent annually. Shale companies will need to drill more wells just to keep producing the same volume of oil. If Eagle Ford, Bakken and Permian production all stagnate or decline, that could constrain the amount of oil the U.S. is able to produce in the long run.

That’s assuming no new reserves are discovered. But, in fact, new reserves are discovered often – even in the Permian itself. In December, the U.S. Department of the Interior reported that the Permian’s Wolfcamp and Bone Spring Formations contain the most oil and gas resources of any location ever assessed. Still, that was not an assessment of proven reserves – those that can be recovered using existing technology – but rather of undiscovered reserves – defined by the department as “resources postulated, on the basis of geologic knowledge and theory, to exist outside of known fields of accumulations” – and technically recoverable reserves – defined as “resources producible using currently available technology and industry practices.” For now, companies are poised to continue producing enough to fuel growth in U.S. oil production. But if Permian production stagnates, they may well have to keep finding more reserves – and ways to extract them – to make it last.

What’s Ahead for Shale

The cycle of the oil industry goes on. Demand for oil may decline as countries shift toward fuel-efficient and electric vehicles. But demand for petrochemicals (chemical products for which oil is an input) will continue to grow as more people in the world’s most populous countries – namely, India and China – move into the middle class. The growing demand for oil will drive prices up, enabling shale drillers to increase production and, therefore, producers to rely less on debt – and even to start paying dividends.

It’s no surprise, then, that countries that rely heavily on the oil industry are having to rethink the underpinnings of their economies. (Saudi Arabia, for example, is working to reconfigure its economy to depend less on oil.) The U.S. could also become energy independent, which could have significant geopolitical implications.

The combination of hydraulic fracturing and horizontal drilling, which paved the way for the shale revolution in the U.S., is out of the box and can’t be put back in. The technology will continue to allow the U.S. to produce large quantities of oil for the foreseeable future. Shale isn’t going anywhere – and it will have a major influence over the global economics of oil for at least the next decade.

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New completion designs, breakevens help Bakken break records

 

A historic, decades-old oilfield in North Dakota is responsible for one of the highest barrel per day initial production rates ever recorded from a well on land in the U.S. The record-breaking well highlights how advanced completions in the Bakken shale play have become, and why the play is still leading the world in technological advancements deployed in the field. The Antelope field hosted a well that surpassed 10,000 barrels of oil per day (16,000 barrels of oil equivalent if the natural gas produced from the well was factored in), according to Lynn Helms, director of the department of mineral resources for North Dakota. Helms talked about the well and the impact of enhanced completions on the Bakken during his monthly update to industry and stakeholders.

“We are seeing the effects of remarkable wells,” he said. “There is almost no where you can drill where you can’t make money.”

New completion designs are expanding the perceived core of the Bakken and Three Forks formation by roughly 40 to 50 miles in some cases. According to Helms, the wells still decline but they start out with production rates that are 50 percent higher than previous versions and also remain producing at sustained levels that are also

 

50 percent higher than wells producing for a similar time frame that were also previously drilled and completed in a similar area.

“Virtually everywhere is economic,” he said.

Starting in mid-March, the Bakken reached roughly 25 frack crews after weather hampered operations in the Williston Basin for the winter months. By mid-summer, there should be approximately 50 frack crews operating in the state.  “Everything is moving at a rapid pace now. Road restrictions are off,” he said, adding that some counties have seen a big uptick in activity and workover and completion work is really taking off.

Later this year, oil production should once again begin breaking records. Natural gas production continues to rise. In March, natural gas production rose 6.5 percent from the previous month. Prices remain low for gas and natural gas liquid takeaway capacity still remains inadequate. Other states with shale gas plays have expressed similar issues as North Dakota, he noted, adding that all states are now accustomed to massive gas production volumes from new wells. In North Dakota, the volume of gas captured is at an all-time high, but supply is outpacing takeaway capacity.

On the crude-by-rail front, the state intends to file a lawsuit against the state of Washington related to new crude-by-rail vapor pressure restrictions the state has planned to start later this summer. According to Helms, the lawsuit is based on a violation of interstate commerce laws and the science behind the Washington law.

With 1,800 job openings for oil and gas positions in the state, Helms said they are also sharing the same issues of other states that have shale plays: they all need more workforce. The state has plans to develop new options for high school workers and streamline the process of getting into certain jobs. In the next two years, projections show the state will need to fill 3,500 jobs each year to meet the need of the oil and gas industry.

Permitting for new wells is still strong at roughly 100 to 150 permits per month. Oil prices are expected to rise due to global turmoil and throughout the year, Helms expects the Bakken and Three Forks (where 99 percent of the new wells are being drilled) to add drilling rigs.

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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.

marissa.luck@chron.com, erin.douglas@chron.com

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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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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.

 


Visit source site

https://eia.gov/todayinenergy/

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Deepwater Texas Oil Port Developer Seeks MARAD License

Dallas-based Sentinel Midstream, LLC reported Monday that its Texas GulfLink, LLC subsidiary last week submitted a license application with the U.S. Maritime Administration (MARAD) to construct and operate a deepwater crude oil export facility off the coast of Freeport, Texas.

According to Sentinel, the proposed Texas GulfLink terminal would be capable of fully loading very large crude carrier (VLCC) vessels. Currently, the U.S. is home to just one deepwater crude oil port facility: the Louisiana Offshore Oil Port (LOOP).

The Texas GulfLink project calls for developing an onshore oil storage terminal connected via 42-inch-diameter pipeline to a manned offshore platform approximately 30 miles off the Gulf Coast, Sentinel stated. Oil would be transported from the platform to two single point mooring buoys, which would enable VLCCs to receive 2 million barrels of crude oil loaded at rates up to 85,000 barrels per hour, the firm added.

“With the submission of the license application to MARAD, Texas GulfLink has completed a major milestone towards receiving approval to construct and operate a deepwater crude oil export facility,” Jeff Ballard, Sentinel’s president and CEO, said in a written statement emailed to Rigzone. “As the neutral infrastructure export solution for shippers, Texas GulfLink will provide a necessary crude oil export outlet for the expected increase in U.S. crude oil production.”

Sentinel added that Cresta Fund Management is providing project financing and Abadie-Williams served as Texas GulfLink’s primary engineering and regulatory consultant.

“We are pleased with the commercial support Texas GulfLink has received and the continued strong interest from shippers who recognize the need for additional export capacity,” noted Chris Rozzell, Cresta managing partner. “By reducing capacity constraints in Gulf Coast ports and creating an economic oil export outlet, Texas GulfLink will allow U.S. oil producers to continue to develop and increase U.S. oil production without potential production curtailments due to lack of export capacity.”

Other firms vying to develop deepwater crude oil port facilities offshore Texas include Trafiugura US Inc. and Enterprise Products Partners L.P. Trafigura’s Texas Gulf Terminals project would be located near Corpus Christi. Enterprise’s Sea Port of Texas (SPOT) project would be located offshore Freeport. Additionally, Lone Star Ports, LLC – a joint venture of The Carlyle Group and The Berry Group – have proposed building an onshore export facility near Corpus Christi that could load VLCCs.

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Oil & Gas Leaders Look for Cost Reduction and Efficiency Gains

 

Houston – Speaking at the closing of the AIPN 2019 International Petroleum Summit (IPS), Ryan Lance, Chairman and Chief Executive Officer of ConocoPhillips spoke about his company’s “hyper focus on returns” highlighting that the “returns the energy industry has generated have been negative over the last 10 to 15 years. Investors are frustrated. We chase the cycle up only, they have to chase the cycle back down on the back side. We recognize it’s a mature industry growing at 1 percent per year. There’s a lot of companies, some tremendous companies … that have dramatic growth profiles. But when they put a hundred percent of their cash flow back into the business, don’t pay the shareholder a fair amount of money, they’re actually destroying value in the long run.

You’ve got to pay your shareholder upfront, you’ve got to be able to grow and develop your company off the cash flow that’s left over and you’ve got to have a focus on returns on capital employed.”

Technology was a constant theme throughout the two days of the IPS with many of the speakers agreeing that technology is going to play a great part in generating future value. Ryan Lance said, “The revolution that we’ve got going on inside our company is embracing technology, innovation and analytics…is it’s not so much about adding another rig it’s about how do you get more work done with that rig that you’ve got.”

 

Alma Del Toro President, Blue Bull Energy believes that, “Technology, such as unmanned platforms, will change the entire nature of the joint operating agreements. Technology is changing the game plan.” However, she pointed out that, “For a CEO choosing the right technology presents its own challenges.”

With panels on Venezuela and Brazil as well as several sessions on Mexico delegates recognized that South America, despite the huge amount of change in the last six months, would provide important opportunities for the industry’s expansion. When commenting about the political changes in Mexico Alma Del Toro said, “Shell, Murphy and Jaguar have reaffirmed my belief that the new administration has not changed much and that Mexico is open for business. Permits are getting issued and nothing has stopped.”

About the AIPN: The Association of International Petroleum Negotiators is an independent not-for-profit professional membership association that supports international energy negotiators around the world and enhances their effectiveness and professionalism in the international energy community. Founded in 1981, AIPN has over 3,000 members in more than 110 countries, representing international and national oil and gas companies, governments, law firms and academic institutions.

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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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