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

[Justin Hicks + 162]

On 5/17/2019 at 1:42 PM, ceo_energemsier said:

 

They are getting regional gas from Haynessville and others plus East TX Cotton Valley and also Eagle Ford and Permian.

Probably also some NM gas as well. I have a JV for LNG export, supplying 1bcf/day for an LNG facility and it is sourced from our EF production, and Haynesville plus some is fed from NM and Permian.

They'll probably be getting quite a bit from Oklahoma as well. 4 years ago SK energy and Continental Resources entered into a 20 year agreement that South Korea will be provided with shale gas from Oklahoma's SCOOP/STACK area in exchange for a tidy investment into Continental acerage.

Edited June 21, 2019 by Justin Hicks

[Douglas Buckland + 6,308]

On 5/21/2019 at 10:54 PM, ceo_energemsier said:

Typical Worker’s Pay Nears $200,000 at Oil Refiner

 

Workers at oil and gas companies ranked near the top in median pay, as shale boom squeezed already tight labor market.

It was a fruitful year for the rank and file at oil-and-gas companies, from Exxon Mobil Corp. to Phillips 66.

Oil and gas drillers and refiners had some of the highest-paid median workers in the energy and utility sectors in 2018, according to The Wall Street Journal analysis of annual pay disclosures by hundreds of big U.S. companies.

Houston-based Phillips 66 paid its median worker $196,407, the highest of any company in the sector. Phillips was followed by Anadarko Petroleum Corp. at $183,445. Oil giant Exxon Mobil, which has roughly 72,600 employees, according to its latest proxy, had the third-highest median worker pay with $171,375.

Phillips 66 and Anadarko both boosted their 2018 median pay by about 15% in 2018 compared with 2017. Exxon raised its median pay about 6%. Oil-and-gas companies typically pay their workers better than many other sectors because they have fewer low-paid retail jobs and must compete in a tight labor market driven in part by the shale-oil boom.

Phillips 66 and Exxon declined to comment beyond their proxy statements. Anadarko Petroleum didn’t respond to requests for comment.

Utility companies, such as Xcel Energy Inc. and American Electric Power Co., were closer to the energy and utility sector’s median of about $117,000, the highest median of any sector in the S&P 500. An American Electric Power spokeswoman said its compensation plan takes into account employee performance and that the company compares its pay levels to its peers. Xcel Energy didn’t respond to requests for comment.

The lowest-paid median employee in the energy sector worked at Marathon Petroleum Corp., earning $27,703. Unlike other oil and gas producers, Marathon operates roughly 3,900 Speedway convenience stores with about 40,000 employees, most of whom are part-time and work lower-wage jobs, according to Marathon’s latest proxy filing.

Without Speedway, Marathon’s median worker pay is $167,607, according to its proxy filing. The company claims in its filing that it is the only domestic downstream refining company with a substantial retail presence.

I would like to see the definition of 'median worker' as it is used in this article. The information presented sounds fishy to me.

Did all who reported include their 'lowest paid median workers'?

[wrs + 893]

10 hours ago, Douglas Buckland said:

I would like to see the definition of 'median worker' as it is used in this article. The information presented sounds fishy to me.

Did all who reported include their 'lowest paid median workers'?

Refinery workers always have made good money.  A lot of the jobs are still unionized.  I had friends come out of high school making more than me after I graduated with two degrees from college.  One of my friends was making $50,000/yr back in 1979 just on overtime and shift differential.  He worked on the train at the Ethyl plant on the Houston Ship Channel.

[ceo_energemsier + 1,818]

Pres. Trump threatens to lessen US security role in Strait of Hormuz, unveils sanctions

In tweet, Trump signals change to 40-year-old maritime security doctrine

Analyst sees move as a negotiating tactic amid heightened US-Iran tensions

US unveils new sanctions on Iranian leaders following attacks on drone, tankers

 

President Donald Trump signaled Monday that the US may lessen its role in the Strait of Hormuz as domestic oil and gas output grows and US energy imports from the Middle East decline.

"China gets 91% of its Oil from the Straight [sic], Japan 62%, & many other countries likewise," Trump wrote in a pair of tweets Monday. "So why are we protecting the shipping lanes for other countries (many years) for zero compensation. All of these countries should be protecting their own ships on what has always been....a dangerous journey. We don't even need to be there in that the US has just become (by far) the largest producer of Energy anywhere in the world!"

Trump's tweets indicated a weakening of a nearly 40-year-old US policy to defend national interests in the Persian Gulf at a time when key administration officials and allies have been attempting to reassure allies of the US commitment to safe transport of energy through the Strait of Hormuz as tensions increase between the US and Iran.

"I don't think it's a full doctrinal change, but I think it's a partial one," Scott Modell, Rapidan Energy Group's managing director and head of geopolitical risk service, told S&P Global Platts Monday.

Modell said Trump's tweets were likely a tactic aimed at bringing Iran to the negotiating table, or at least pausing military escalation between the two nations.

US Secretary of State Mike Pompeo met Monday with Saudi King Salman and Crown Prince Mohammed bin Salman to discuss the regional tensions and the "need for stronger maritime security to promote freedom of navigation in the Strait of Hormuz," the State Department said in a statement. Pompeo is traveling to Saudi Arabia, the UAE, India, Japan and South Korea this week, part of an effort to build a coalition against Iran.

The governments of Saudi Arabia, UAE, the UK and the US issued a joint statement Monday calling on Iran to "halt any further actions which threaten regional stability, and urge diplomatic solutions to de-escalate tensions.

"These attacks threaten the international waterways that we all rely on for shipping," the governments said, according to a statement released by the US State Department. "Ships and their crews must be allowed to pass through international waters safely."

In a tweet Monday, Senator Lindsey Graham, Republican-South Carolina, wrote that "safe navigation of sea lanes -- vital to a world economy -- is always in America's national security interest."

Last week, however, Air Force General Paul Selva, vice chairman of the Joint Chiefs of Staff, told reporters that while the US has defended freedom of navigation through the Strait of Hormuz for decades, maritime security was not "a US-only problem."

"If we take this on as a US-only responsibility, nations that benefit from that movement of oil through the Persian Gulf are bearing little or no responsibility for the economic benefit they gain from the movement of that oil," Selva said, according to a Defense News report.

In a tweet Monday, Javad Zarif, Iran foreign minister, wrote that Trump is "100% right that the US military has no business in the Persian Gulf."

About 20.7 million b/d of oil, or about 21% of global petroleum liquids demand, flows through the Strait of Hormuz each day, according to the US Energy Information Administration.

"Flows through the Strait of Hormuz in 2018 made up about one-third of total global seaborne traded oil," EIA said in a recent report. "More than one-quarter of global liquefied natural gas trade also transited the Strait of Hormuz in 2018."

It is unclear on what data Trump based his tweet claiming that China got 91% of its oil from the Strait of Hormuz. From January through April, China imported less than 44% of its crude oil from the Middle East, according to China's General Administration of Customs.

Still, US imports of Middle Eastern crude have reached historic lows as US oil output continues to shatter records, data shows.

US oil imports of crude oil from Persian Gulf countries averaged less than 1.05 million b/d in March, down from a peak of nearly 3.08 million b/d in April 2003, according to the US EIA. US oil output grew to over 11.9 million b/d from about 5.73 million b/d over the same time period, according to EIA data.

MORE SANCTIONS

The US, which reimposed oil sanctions on Iran in November, allowed sanctions waivers given to Iran's biggest crude and condensate buyers to expire in early May.

Iranian crude oil and condensate exports, which averaged about 1.7 million b/d in March, fell to about 1 million b/d in April and an estimated 800,0000 b/d in May, according to  trade flow software, and shipping sources. The majority of those flows in May were to China, Turkey and Syria, according to these sources.

Modell with Rapidan said he expects the Trump administration, which has sanctioned all oil exports out of Iran with a stated aim of pushing Iran exports to zero, would need to formally allow about 1.2 million b/d of oil exports out of Iran for nuclear talks between the two sides to commence.

The US Department of the Treasury on Monday sanctioned Iranian Supreme Leader Ayatollah Ali Khamenei and eight senior Islamic Revolutionary Guards Corps commanders, freezing any US assets they hold and blocking them from the US financial system. Any foreign financial institutions that knowingly facilitate significant financial transactions with them could also be cut off from the US banking system.

Treasury Secretary Steven Mnuchin said the additional sanctions would be "highly effective" at increasing pressure on Iran. He said he did not consult European or other allies about the new measures.

Mnuchin declined to say whether last week's shooting down of an unarmed drone over the Gulf of Oman or recent oil tanker attacks triggered the latest sanctions.

"Some of this was in the works; some of this was in response to recent activities," he said during a White House briefing.

Trump tweeted Friday that the US had prepared a strike against Iran Thursday night, but he had called it off with 10 minutes to spare.

[ceo_energemsier + 1,818]

Monthly U.S. Crude Oil Imports from OPEC Fall to a 30-Year Low

 

U.S. imports of crude oil from members of the Organization of the Petroleum Exporting Countries (OPEC) in March 2019 totaled 1.5 million barrels per day (b/d), their lowest level since March 1986, based on data in EIA’s Petroleum Supply Monthly. U.S. crude oil imports from OPEC members have generally fallen over the previous decade as domestic crude oil production has increased.

 

 

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Source: U.S. Energy Information Administration, Petroleum Supply Monthly

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From the early 1980s through the late 2000s, OPEC member countries were the source of about half of all U.S. crude oil imports. In the past decade, however, total U.S. crude oil imports have fallen and OPEC’s share of those imports has decreased. Non-OPEC countries such as Canada, Mexico, Brazil, and Colombia have made up larger shares of U.S. crude oil imports. In each of the past four years, Canada alone has supplied more crude oil to the United States than all OPEC members combined.

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Source: U.S. Energy Information Administration, Petroleum Supply Monthly

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Through the first three months of 2019, U.S. crude oil imports from OPEC members Venezuela and Iraq have fallen the most. In 2018, Venezuela was the source of 505,000 b/d of U.S. crude oil imports, or 20% of the OPEC total. In March, the United States imported just 47,000 b/d of crude oil from Venezuela. Preliminary weekly import valuesshow several weeks in March and May when the United States imported no crude oil from Venezuela.

U.S. sanctions directed at Venezuela's energy sector generally and Petróleos de Venezuela, S.A. specifically have driven U.S. imports from Venezuela to recent low levels. Before the United States imposed the sanctions, U.S. imports had been declining as long-term mismanagement of Venezuela’s oil industry, and widespread power outages since the beginning of this year have led to significant declines in Venezuelan crude oil production.

U.S. crude oil imports from other OPEC members also declined following a November 2016 agreement by OPEC members and a number of non-OPEC producers to cut crude oil production. As a result of the production cuts, many OPEC members reduced exports to the United States in favor of growing markets in Asia. In the first three months of 2019, the volume of U.S. crude oil imports from Saudi Arabia and Iraq—the two largest sources of imports from OPEC in 2018—have averaged 26% and 28% below their 2018 average levels.

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Source: U.S. Energy Information Administration, Petroleum Supply Monthly

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In 2018, the U.S. Gulf Coast region (defined as Petroleum Administration for Defense District 3) imported 1.4 million b/d of OPEC crude oil, or 55% of the national total of OPEC imports. With the recent decline, the U.S. Gulf Coast imported just 513,000 b/d from OPEC in March 2019. U.S. Gulf Coast imports of OPEC crude oil in March were below those for the West Coast region, marking the first time on record that the Gulf Coast region was not the predominant import area of OPEC crude oil in the United States.

For total crude oil imports, the Midwest (defined as Petroleum Administration for Defense District 2) has received more crude oil than the Gulf Coast in every month from November 2018 through March 2019, the latest available monthly value. Nearly all of the Midwest’s crude oil imports come from Canada.

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Source: U.S. Energy Information Administration, Petroleum Supply Monthly

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The decline in Gulf Coast crude oil imports and the recent rise in crude oil exports has led the Gulf Coast region to be a net exporter of crude oil in every month from November 2018 through March 2019. More than 90% of the U.S. crude oil exported since the start of 2018 has been shipped from Gulf Coast ports.

[ceo_energemsier + 1,818]

This Week in Petroleum

Release date: June 5, 2019  |  Next release date: June 12, 2019

Lowest crude oil imports since 1986 indicate changes in U.S. Gulf Coast crude oil supply

U.S. Gulf Coast crude oil imports averaged 1.8 million barrels per day (b/d) in March 2019, the lowest level since March 1986 and significantly lower than the peak of 6.6 million b/d in March 2007. Preliminary weekly data indicate that Gulf Coast crude oil imports have averaged about 1.9 million b/d through April and May (Figure 1). Falling crude oil imports into the U.S. Gulf Coast so far in 2019 are the result of both recent events and continuing longer-term trends. Recently, sanctions on Venezuelan imports and heavy refinery maintenance have reduced imports. At the same time, imports to the Gulf Coast have also decreased because of sharp declines in imports from the Organization of the Petroleum Exporting Countries (OPEC) following an agreement among members to reduce production and because imports are being replaced by increased production of domestic crude oil. Together, these trends have fundamentally changed how the Gulf Coast region is supplied with crude oil. In the past five consecutive months, the U.S. Gulf Coast has exported more crude oil than it imported (net exports), and since 2015, it has consistently received more crude oil from other regions of the United States than it has sent to other regions (net receipts).

Gulf Coast crude oil imports are typically lower in the early months of the year as refineries reduce runs as part of their seasonal maintenance. This year, planned maintenance activity was higher than usual. The four-week average of gross refinery inputs in the Gulf Coast fell from 9.6 million b/d for the week ending January 4, higher than the five-year (2014-18) maximum and 648,000 b/d higher than the five-year average, to a low of about 8.6 million b/d from mid-February until mid-April. Although 8.6 million b/d of gross refinery inputs is more than the Gulf Coast’s five-year average level for the period, eight consecutive weeks of relatively flat refinery runs is longer than normal during refinery maintenance at this time of year. This extended period of lower refinery runs for longer in the early months of 2019 reduced the need for crude oil imports, contributing to the more-than-three-decade-low crude oil imports during this period.

Around the same time, the U.S. government announced additional sanctions on Venezuela that included limitations on crude oil imports from Venezuela. In 2018, 20% of all Gulf Coast crude oil imports were from Venezuela, an annual average of 498,000 b/d. The Gulf Coast was the destination for 98% of all U.S. imports of Venezuelan crude oil in 2018. Because of the imposition of sanctions, refiners in the Gulf Coast sharply reduced imports of Venezuelan crude oil. Between January and March 2019, Gulf Coast imports of crude oil from Venezuela fell by 498,000 b/d to 47,000 b/d in March. As a result of the Gulf Coast reductions, U.S. four-week average imports from Venezuela fell from 603,000 b/d for the week ending January 25 to 12,000 b/d for the week ending May 31 (Figure 2).

An additional change in Gulf Coast crude oil imports occurred following a November 2016 agreement by OPEC members to cut crude oil production. As a result of the production cuts, many OPEC members reduced exports to the United States in favor of growing markets in Asia. One year after the production-cut agreement, crude oil imports from OPEC processed at Gulf Coast refineries had fallen 562,000 b/d from 2.1 million b/d in November 2016 to 1.5 million b/d in November 2017. Imports of crude oil from OPEC members into the Gulf Coast continued to decline, falling to 1.4 million b/d in 2018 and down to 513,000 b/d in March 2019 (Figure 3).

Before the OPEC production cuts in 2016, the Gulf Coast had already started reducing crude oil imports because of rising domestic production and changes in domestic crude oil pipeline infrastructure. Gulf Coast crude oil production increased from 2.7 million b/d in 2008 to 7.9 million b/d in March 2019. Much of this increased crude oil production was of light sweet crude oil that allowed Gulf Coast refineries to reduce imports of light sweet crude oil from foreign sources. Then pipeline infrastructure that once took imported crude oil from the Gulf Coast and delivered it to other regions of the United States was reversed, instead delivering increased domestic crude oil production and imports from Canada to Gulf Coast refineries. By 2015, this reversal meant that the Gulf Coast changed from being a net shipper of crude oil to other U.S. regions to being a net recipient. More recently, as imports have declined and crude oil exports have expanded, the Gulf Coast actually exported more crude oil than it imported for five consecutive months (Figure 4).

Because of all these changes combined, foreign-sourced crude oil receipts at Gulf Coast refineries accounted for an average of 36% of Gulf Coast refinery crude oil inputs in 2018, compared with 73% in 2008. The sources of those imports have also changed, with Canada and Mexico accounting for 54% of all imported crude oil processed in Gulf Coast refineries in March, representing a new high.

U.S. average regular gasoline and diesel prices fall

The U.S. average regular gasoline retail price fell nearly 2 cents from the previous week to $2.81 per gallon on June 3, more than 13 cents lower than the same time last year. The Gulf Coast price fell nearly 5 cents to $2.42 per gallon, the West Coast price fell nearly 4 cents to $3.60 per gallon, and the East Coast price fell more than 3 cents to $2.66 per gallon. The Midwest price rose more than 3 cents to $2.75 per gallon and the Rocky Mountain price increased slightly, remaining at $2.98 per gallon.

The U.S. average diesel fuel price fell nearly 2 cents to $3.14 per gallon on June 3, nearly 15 cents lower than a year ago. The West Coast price fell more than 2 cents to $3.76 per gallon, the Rocky Mountain and Gulf Coast prices each fell nearly 2 cents to $3.16 per gallon and $2.88 per gallon, respectively, and the Midwest and East Coast prices each fell over 1 cent to $3.03 per gallon and $3.15 per gallon, respectively.

Propane/propylene inventories rise

U.S. propane/propylene stocks increased by 2.5 million barrels last week to 68.3 million barrels as of May 31, 2019, 9.1 million barrels (15.4%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Gulf Coast inventories increased by 1.2 million barrels, and Midwest and East Coast inventories each increased by 0.7 million barrels. Rocky Mountain/West Coast inventories decreased slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 7.2% of total propane/propylene inventories.

For questions about This Week in Petroleum, contact the Petroleum Markets Team at 202-586-4522.

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Retail prices (dollars per gallon)

	Retail prices	Change from last
	06/03/19	Week	Year
Gasoline	2.807	-0.015	-0.133
Diesel	3.136	-0.015	-0.149

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Futures prices (dollars per gallon*)

	Futures prices	Change from last
	05/31/19	Week	Year
*Note: Crude oil price in dollars per barrel.
Crude oil	53.50	-5.13	-12.31
Gasoline	1.802	-0.133	-0.341
Heating oil	1.842	-0.129	-0.334

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Stocks (million barrels)

	Stocks	Change from last
	05/31/19	Week	Year
Crude oil	483.3	6.8	46.7
Gasoline	234.1	3.2	-4.9
Distillate	129.4	4.6	12.6
Propane	68.272	2.520	21.159

[ceo_energemsier + 1,818]

US crude inventories fell last week amid a surge in export activity, US Energy Information Administration data showed Wednesday.

Commercial crude stocks dipped 3.11 million barrels to 482.36 million barrels during the week ended June 14, the EIA data showed. The draw brought in the surplus to the five-year average to 8.35%, narrowing the supply overhang for the first time in eight consecutive weeks.
The inventory draw was concentrated on the US Gulf Coast, where storage levels fell 5.83 million barrels to a six-week low at 241.28 million barrels. A key driver of this draw was a 300,000 b/d surge in exports to 3.42 million b/d, the second-highest weekly figure on record and just 5% below the all-time high reported by the EIA in mid-February.

USGC export volumes to Europe rose for a fifth straight week to 8.12 million barrels, a 1.14 million barrel uptick from the week prior, according to cFlow, Platts trade flow software.

WTI has become increasingly competitive in Europe amid the rapid build out of a supply overhang in recent weeks. To-date in June, WTI has averaged at slightly more than a $2.00/b discount compared to Dated Brent delivered into Rotterdam, up from around a $1.00/b discount averaged in May and a 60 cent/b discount in April, Platts calculations showed.

But arbitrage economics for US crudes in Asia continue to dim relative to Middle Eastern grades. To date in June, WTI delivered into North Asia has averaged at a 70-cent/b premium compared with Murban crude in North Asia, Platts calculations showed, up from a 31-cent/b premium in May. US crude outflows to Asia fell back 3.17 million barrels to 8.477 million barrels last week, a 27% decline from week-ago levels, according to cFlow data.

Notably, crude stocks were higher across all other regions outside of the Rockies, where they slipped 171,000 barrels to 23.3 million barrels.

In the Midwest, crude inventories were 748,000 barrels higher last week at 146.55 million barrels. The bulk of this build — 642,000 barrels — was realized at Cushing, Oklahoma, the delivery point of the NYMEX crude contract. The build pushed inventories there to the highest since November 2017, and came despite a 7.8 percentage point bump in Midwest refinery runs rates that took regional utilization to the highest since mid-January at 95.9% of total capacity.

A 961,000 barrel-build on the US Atlantic Coast pushed inventories there to 16.22 million barrels, the highest since August 2017, and West Coast stocks were just shy of 12-month highs after building 1.12 million barrels to 55.02 million barrels.

GASOLINE STOCKS DRAW AMID RECORD-HIGH DEMAND
Total gasoline inventories fell 1.7 million barrels last week to 233.22 million barrels, EIA data showed. The draw ran counter to analysts expectations of a 1 million-barrel build in a Platts Monday analysis and sent NYMEX RBOB futures sharply higher in midmorning trading.

The draw was predicated in large part upon record-high end-user demand levels. Total product supplied for gasoline, a proxy for demand, edged up 51,000 b/d to 9.93 million b/d — the highest weekly figure ever reported by EIA. Gasoline demand was 4.75% stronger than the five-year average for this time of year.

USAC gasoline inventories dipped 1.4 million barrels to 62.15 million barrels, taking stocks 3.9% below the five-year average. Rising refinery utilization in the Midwest contributed to a 620,000 barrel increase in regional gasoline stocks to 48.95 million barrels, but despite the uptick inventories were still 4.8% below the five-year average and nearly 7% under year-ago levels.

Distillate stocks also showed a counter-consensus draw last week, slipping 550,000 barrels to 127.82 million barrels.

Midwest combined low and ultra-low sulfur diesel stocks fell 325,000 barrels to 31.65 million barrels, narrowing the regional surplus to the five-year average to 3.1% — the lowest since late March. Flooding and severe weather across the Midwest this spring has impacted regional farming activity and weighed on diesel demand, contributing to local price discounts. The Platts Chicago ULSD differential to NYMEX ULSD averaged at minus 19.5 cents/gal last week, compared with minus 9.05 cents/gal during the week prior. But after peaking at minus 21.25 cents/gal late last week this spread has sharply narrowed, coming in to minus 8.5 cents/gal on Tuesday, the latest day data is available.

[ceo_energemsier + 1,818]

The opportunity and threat posed by US shale water

 

The sourcing, handling, and disposal of water is an increasing issue in US tight oil and gas operations and represents both a threat to operators and an opportunity for the supply chain. Both well count and completion intensity have grown in recent years and rising pressure from environmental regulations – e.g. federal Clean Water Act, Colorado’s Senate Bill 181, etc. – means that water management has become a key focus for operators, specifically produced water disposal and recycling.

Following the downturn, the recovery in activity levels translated to not only an increase in the number of wells completed, but more importantly longer laterals using more proppant (frac sand) and water per foot during hydraulic fracturing, which created more flowback and produced water. In the Delaware Basin, the water cut for wells has increased from an average of c.70% to c.72% since 2016.

Delaware Basin Water Cut Rate (2016-2019)
Source: Energent

Based on data from Westwood’s Energent service, a Centennial Resources 2-mile lateral in the basin uses c.26 million pounds of 100 mesh frac sand and c.22 million gallons of water to achieve a 47-stage fracture. With the rise of multi-well pads, these high-intensity completion practices have led to the overall increase of per well production resulting in a rise of US onshore liquids production, including water.

Produced water management costs have significantly increased for operators due to the rising number of truckloads per well required and a shortfall of available disposal or treatment capacity within reasonable distance. Pricing for disposal via road tankers currently ranges between $0.30 to $2.00+ per barrel depending on available supply, location of salt water disposable wells and local area regulations. Numerous service companies and operators have filed additional salt-water disposal well permits to handle the increase in produced water. Additionally, investment in water infrastructure created a new “water midstream” service company category.

Sample of “Water Midstream” companies in the Permian
*SWD = Salt Water Disposal
Source: Company websites

 

 

Westwood’s analysis suggests that continued investment in water midstream along with operator collaboration will likely encourage a gradual shift towards using dedicated pipelines instead of trucks which would be a safer, more reliable, and more economical long-term solution. Secondly, using more recycled water for hydraulic fracturing would reduce requirements for sourcing fresh water as well as reduce the produced water surge for disposal, significantly alleviating the increasing water management burden on operators. Successfully developing and maintaining an adequate new transportation and recycling infrastructure is challenging but does present opportunities for service providers.

Currently, only a handful of players have been aggressively developing in-field produced water treatment and recycling services. Despite competing with large OFS contractors and their technological leadership, smaller specialist contractors could likely develop and offer specific services (e.g. temporary water piping, water treatment, etc.) or the full range of recycling services at more competitive price points than large OFS contractors. Also, management services to prevent plugging, corrosion and growth of bacteria in pipelines, and optimized and cost-effective recycling plants will likely be required.

Water management to date has been basin specific. Private equity and infrastructure funds’ interest in “water midstream”, as demonstrated by their backing of companies such as Layne Water Midstream (Post Oak Energy Capital / Genesis Park), Waterfield Midstream (Blackstone), Water Bridge (GIC) and H2O Midstream (EIV Capital), presents a unique opportunity to create water services that scale across the US shale plays.
Source: Westwood Global Energy Group

[ceo_energemsier + 1,818]

US Oil Production Hits New All Time High

U.S. crude oil production reached a new all time high of 12.2 million barrels per day (MMbpd) in May.

That’s according to the American Petroleum Institute’s (API) latest monthly statistical report, which revealed that Texas crude oil output exceeded 5 MMbpd last month for the first time.

“These milestones were achieved despite less drilling activity, which is testament to productivity but also pipeline infrastructure expansions that helped enable drilled but uncompleted wells to come to market,” the API report stated.

Last month also saw record U.S. petroleum exports at 8.1 MMbpd and a U.S. crude oil inventory increase of 10.5 percent over May 2018, the report revealed.

In its second quarter industry outlook report, released on the same day as the latest monthly statistical report, the API said the United States is poised for a continuation of record oil production. This report also highlighted that while U.S. crude oil export capacity has been “sufficient”, some capacity estimates suggest “some urgency to plan forward”.

“The historic milestones in U.S. oil production this quarter underscore the necessity of pipeline infrastructure to continued U.S. energy leadership,” API Chief Economist Dean Foreman said in an organization statement.

“With the surge expected to continue, our focus must now shift toward ensuring the necessary infrastructure and logistics are in place to support growth in providing energy to consumers, as well as exports,” he added.

“If current predictions by the U.S. Energy Information Administration and others prove correct, the U.S. will likely push up against the lower bound of existing crude oil export capacity by the end of this year, which creates urgency around building new infrastructure to ensure we don’t miss out on this rare opportunity,” Foreman continued.

Earlier this month, Rystad Energy stated that U.S. crude output would hit 13.4 MMbpd by December and average 12.5 MMbpd in May.

The API describes itself as the only national trade association representing all facets of the natural gas and oil industry. The API has more than 600 members, including large integrated companies, exploration and production, refining, marketing, pipeline, marine businesses and service and supply firms.

[ceo_energemsier + 1,818]

Shale gas from Permian to source new plastics plant near Gulf

 

Food packaging, construction materials and agricultural films may soon be produced from shale gas sourced from the Permian Basin. Gulf Coast Growth Ventures LLC, a joint venture between ExxonMobil and Saudi Basic Industries Corp., has asked its construction company, Zachry Group, to place an order for a 1.3-million-ton polyethylene plant near Corpus Christi, Texas.

The polyethylene plant will be part of a larger shale gas-fed plastics plant built in the area. Zachry Group has placed an order for the plant design, supply and procurement of equipment and building of certain modules with Mitsubishi Heave Industries Engineering from Tokyo.

The original order for the plant was placed in 2017. Mitsubishi was selected in part for its ability to create the plant around a modular construction process that will help bring the plant online sooner. Mitsubishi and ExxonMobil previously worked together on polyethylene plants in Singapore in 2011 and Texas in 2017.

According to Mitsubishi, “the U.S. chemical plant market is expanding rapidly with increased production of shale gas.”

Once complete, the plant would create more than 600 permanent jobs with an average salary of roughly $90,000 per year. The GCGV joint venture was formed in 2018 and has always been focused on building the shale gas facility.

[ceo_energemsier + 1,818]

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

 

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

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

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

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

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

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

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

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Stage Completions records 142-stage Permian shale well

 

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

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

 

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

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Reveal releases FracEYE system to reduce frac hits in shale wells

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

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

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

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

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

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

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Titan tests, proves electric power tongs on DJ Basin rig

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

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

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

 

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

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

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

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

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

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Bakken to surpass record output despite gas bottlenecks

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Ineos taps Texas for USGC EO-EOD plant

Ineos AG will site subsidiary Ineos Oxide’s previously announced project for a proposed US Gulf Coast ethylene oxide and ethylene oxide derivatives plant in Texas.

 

Ineos AG, Rolle, Switzerland, will site subsidiary Ineos Oxide’s previously announced project for a proposed US Gulf Coast ethylene oxide (EO) and ethylene oxide derivatives (EOD) plant in Texas

The new 1.2 billion-lb (520,000-tonne/year) EO unit and associated downstream EOD plant will be built at Ineos’s Chocolate Bayou petrochemicals manufacturing site in Alvin, Tex., south of Houston on the Gulf of Mexico coast, Ineos said.

Selection of Chocolate Bayou to host the new EO-EOD plant will reinforce on-site integration to benefit two existing olefins crackers, two polypropylene units, and two cogeneration installations at the site operated by Ineos Olefins & Polymers USA, according to the operator.

Ineos said it also expects availability of additional land close to the new unit will enable interested third parties to colocate and consume EO by pipeline.

Part of Ineos’s plan to address a fast-growing EO merchant market as well as the operator’s own requirements, the new plant is slated to be operational sometime in 2023.

 

Alongside the site’s proposed EO-EOD plant, Ineos subsidiary Ineos Oligomers also is currently building a new linear alpha olefin (LAO) unit and associated downstream polyalphaolefin (PAO) unit at Chocolate Bayou, both of which are scheduled for startup by yearend 2019

 

 

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

Competition heats up to move next wave of US exports

LOOP is currently only port able to fully load VLCCs

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

 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

KEY FACTS:

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

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

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

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

Edited July 7, 2019 by ceo_energemsier

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How Texas is Making America More Energy Secure

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Key Findings

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

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

 

---

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

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

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

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

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

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

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

---

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

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

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

---

Conclusion

Texas oil and natural gas development is an integral part of U.S. energy security. With unmatched levels of production coming from places like the Permian Basin and the Eagle Ford, the Lone Star State is providing the resources we need domestically, while also supplying our trading partners with a reliable source of affordable energy. Soaring production from Texas has also lowered petroleum’s share of the U.S. trade deficit to almost zero, as growing exports help to shift the country from a net importer to a net exporter. This transition means billions of dollars in revenue, an improved balance of trade and a substantially decreased reliance on foreign countries for our energy needs.

 

 

 

For this energy revolution to continue, however, it’s crucial that the build-out of pipelines and export infrastructure continues. Doing so will mean continued job growth and improved positioning for Texas within the global energy market. But this infrastructure expansion is not possible without a stable regulatory environment. While Texas has proven the ideal location for energy development with its pro-business and low-tax environment, adding burdensome regulations would have dire consequences on production and the Texas economy.

 

 

 

Texas is known around the world for its prolific energy production, and as global demand for oil and natural gas increases in the coming decades, the Lone Star State is well-positioned to capitalize on that opportunity – helping to make America even more energy secure in the process.

 

https://d3n8a8pro7vhmx.cloudfront.net/northtexansfornaturalgas/pages/2367/attachments/original/1561995350/TNG_-_REPORT-02.pdf?1561995350

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Chevron Phillips to build $8B plant on Gulf Coast

 

https://www.chron.com/business/energy/article/Chevron-Phillips-to-build-8B-plant-on-Gulf-COast-14082601.php#photo-16311111

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Exports of U.S. light sweet crude jump at Louisiana port: sources, data

 

https://www.reuters.com/article/us-usa-crude-exports/exports-of-u-s-light-sweet-crude-jump-at-louisiana-port-sources-data-idUSKCN1U41S1

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https://shalecrescentusa.com/

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Big Oil Plans to Unleash a Flood of Plastic From US Gulf
(Bloomberg) -- The world’s biggest oil and chemical companies are about to unleash a tidal wave of plastic raw materials by the mid-2020s, tapping cheap shale gas to meet growing demand from makers of everything from toys to plumbing to consumer goods.

Exxon Mobil Corp., Dow Inc., France’s Total SA, South Africa’s Sasol Ltd. and Saudi Basic Industries Corp. have built or announced at least $40 billion in new petrochemical facilities in Texas and Louisiana, according to data compiled by Bloomberg. The most recent is an $8 billion joint venture between Chevron Corp., Phillips 66 and Qatar Petroleum announced this week.

Companies involved | Projected cost | Location
Sasol | $11.8 billion | Louisiana
Exxon, Sabic | $10 billion | Texas
Chevron Phillips, Qatar Petroleum | $8 billion | U.S. Gulf Coast
Dow | $6 billion | Texas, Louisiana
LyondellBasell Industries NV | $2.4 billion | Texas
Exxon | $2 billion | Texas
Total, Nova Chemicals, Borealis | $1.7 billion | Texas

The investments in Gulf of Mexico coastal factories come amid a consumer backlash against plastic bags and straws for their environmental impact. The total amount of oceanic plastic waste is expected to more than double by 2030 if action isn’t taken now, the International Energy Agency said in a report last year.

In the U.S. alone, New York City, Seattle, Oakland and Miami Beach all have either banned straws or have pending proposals to do so. Boston, Chicago, Los Angeles and San Francisco prohibit plastic bags, while several other cities imposed fees for using plastic bags at grocery stores.

Mark Lashier, chief executive officer of the Chevron Phillips Chemical Co. joint venture that’s partnering with Qatar Petroleum, said he’s not worried about straw or bag bans hitting the plastics industry. Some forecasters see plastic demand growing quicker than oil, which is under threat from renewable energy and electric vehicles.

“We certainly take that into account in our supply and demand balances, but the demand in general for plastic materials is growing greater than 4% a year,” he said. “The world is going to need more and more of this as the world population grows.”