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

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WoodMac Bullish on Exxon Permian Growth Campaign


Wood Mackenzie has revealed that it is bullish on ExxonMobil’s Permian growth campaign.

“Exxon is clearly on target with a development approach unlike anything we’ve seen before in a shale basin,” WoodMac said in a company statement posted on its website on Monday.

“The supermajor is running an unprecedented 60 rigs in the Permian, up three-fold from just 20 rigs a year and a half ago, and it’s just getting started,” WoodMac added.

In March this year, Exxon revealed that it was going to increase its Permian output to 1 million barrels per day by 2024.  

“We’re increasingly confident about our Permian growth strategy due to our unique development plans,” Neil Chapman, ExxonMobil senior vice president, said in a company statement at the time.

“We will leverage our large, contiguous acreage position, our improved understanding of the resource and the full range of ExxonMobil’s capabilities in executing major projects,” he added.

Reacting to Exxon’s announcement back in March, WoodMac described the timing of it as “bold”.

“With infill wells underperforming and decline rates from producing wells accelerating, the timing on this announcement is bold to say the least,” WoodMac stated on March 6.

ExxonMobil, describes itself as one of the world’s largest publicly traded energy providers and chemical manufacturers. WoodMac is an energy research and consultancy company.

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(Bloomberg Opinion) -- America’s second shale boom is running out of steam. But don’t panic just yet, a third one may be coming over the horizon.

The U.S. Energy Information Administration published its latest short-term energy outlook last week and has cut its forecast of oil production by the end of 2020 for the fourth straight month. It now expects American output to rise by just 370,000 barrels a day over the course of next year. That will be the slowest growth in four years and is yet another indicator that the latest period of rapid shale expansion is faltering.

The number of rigs drilling for oil in the U.S. has fallen in each of the last 10 months, dropping by a total of 20% since November. And productivity gains are waning. Drilling in the Permian, the most prolific of the shale basins, fell by 11% in the nine months to August, according to the EIA.

The development of the U.S. shale patch is a bit like that of a person. During the first growth spurt in the four years to 2014 the industry was in the toddler phase. Everything was new and exciting, the toddlers stuck their fingers (or in this case their drill bits) into everything, just to see what would happen, and they pushed the boundaries in every direction. The toddler developed quickly, but the outside world taught it a hard lesson with a crash in the oil price in 2014.

The second boom from 2016 has been more like the adolescent phase. After picking themselves up and learning to live in their changed world, the young adults developed their muscles and concentrated only on the things that interested them (the sweet spots in the shale deposits) to the exclusion of everything else. This focus has brought bigger output gains than the first boom. In the three years between December 2016 and December 2019 output is expected to have increased by 4.2 million barrels a day, compared with 3.9 million barrels a day between December 2010 and December 2014.

The biggest challenges of the second shale boom have been identifying and exploiting those sweet spots, consolidating acreage to enable the use of longer wells, and building infrastructure to move the gas and liquids to markets (including overseas).

But with a WTI oil price of about $50 a barrel, some in the shale patch are struggling. Shale companies are being forced to produce more to service their high debts, but they aren’t making any surplus profit to cut their borrowing or pay shareholders. Now those investors are starting to demand more of a return.

With the crude price seemingly stuck close to where it is — despite the tensions in the Persian Gulf region which flared up again on Friday —  the next round of discussions between the shale producers and their lenders could be difficult. Some mergers may follow.

Yet fans of U.S. oil shouldn’t be disconsolate. The end of the second shale boom will usher in a third: the period of young adulthood. This will bring a range of new skills, but production will grow at a more measured pace.

This third boom will be driven by the international oil majors and will be characterized by a focus on better extraction, rather than rapid output growth. The application of enhanced oil recovery techniques, consolidation of ownership, automation of drilling, and rationalizing of supply chains will increase the volume of oil extracted over the lifetime of a well and reduce costs. But it won’t deliver the same pace of growth as seen recently.

The recovery rate of oil from shale deposits is typically about 5%-10%, but ConocoPhillips has pushed recovery as high as 20% in some parts of the Eagle Ford shale play in Texas, and it could reach 40% under the right circumstances. The upside to the lifetime recovery rate from Eagle Ford would be huge, potentially extending higher production rates for longer.

The third shale boom is coming. Just don’t expect it to look like the first two.

To contact the author of this story: Julian Lee at

To contact the editor responsible for this story: James Boxell at

This column does not necessarily reflect the opinion of the editorial board or Bloomberg LP and its owners.

Julian Lee is an oil strategist for Bloomberg. Previously he worked as a senior analyst at the Centre for Global Energy Studies.

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On 8/31/2019 at 8:44 PM, James Regan said:

Great debate lots of feedback , some say first signs of madness....


What is the first sign of Madness ?

Suggs walking up your driveway. ( followed by Chaz Smash and the rest of the band )

  • Great Response! 1

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5 minutes ago, Auson said:


What is the first sign of Madness ?

Suggs walking up your driveway. ( followed by Chaz Smash and the rest of the band )

First sign of Madness would be a shiny brogue or ox blood Doc Martins (Currently walking around the room in a Ska fashion)

I saw The Beat recently Roger Rankin and his son Junior, fantastic.....

Screen Shot 2019-10-14 at 11.01.16.png

Edited by James Regan
Finding a Rude Boy.....
  • Like 1

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FERC clears 400 MMcf/d Permian project, sets two more pipes for action


Sendero to stretch from processing plant to Waha Hub

Southeastern Trail, Lockridge projects poised for votes


The Federal Energy Regulatory Commission Thursday acted on one of the backlogged natural gas projects in its dockets, the 400 MMcf/d Sendero Carlsbad Gateway project, and put two other pipelines on its agenda for authorization decisions at the commission's October 17 open meeting.




The actions continue to show FERC is able to move on natural gas projects with a strengthened 2-1 Republican majority, although three LNG projects pitched for Brownsville, Texas, and closely watched by the LNG sector, were noticeably left off the agenda for next week.

The 23-mile Sendero pipeline project (CP18-538) would provide takeaway capacity for a recently completed processing plant, owned by a Sendero affiliate, in the Permian Basin, providing transportation capacity to the Waha Hub. Sendero had been reminding FERC to act on the application, arguing that every day of continued delay increased the hardship on producers.

Democratic Commissioner Richard Glick dissented, as he has mostly done on natural gas projects, saying the commission is again assuming away the climate implications of constructing and operating the project.


On tap for FERC decisions October 17 are Natural Gas Pipeline Company of America's 17-mile, 500 MMcf/d Lockridge Extension Pipeline, another Permian Basin area expansion that will provide southbound transportation to the Waha Hub (CP19-52). The project will provide shippers the optionality to move gas southbound targeting Mexican export demand.

Also on the agenda for a vote is Williams' 7.7-mile Southeastern Trail project, intended to add 296 MMcf/d of gas delivery capacity to mid-Atlantic and Southeastern states in time for the 2020-21 winter heating season (CP18-186). Williams in June had asked for action by June 14 so that it could complete work for a November 2020 start. It had previously sought a May 1 decision.

FERC earlier this year appeared stuck on multiple natural gas project decisions amid a 2-2 split over climate change considerations. The departure of Democrat Cheryl LaFleur tipped the balance in favor of the Republican majority, although there have been questions about whether recusals might stymie some decisions.


FERC has gotten some nudges to act on LNG projects in the Brownsville Ship Channel area that received their final environmental documents more than five months ago. In September, Annova LNG pressed FERC for a prompt decision, noting that its potential customers and investors routinely point to delays at FERC as bearing on their financial decisions. Texas LNG also recently put in a request.

While FERC's environmental reviews of each of the three projects pitched in that area found acceptable impacts if mitigation and various plans were followed, the FERC staff reports found significant cumulative impacts of all three projects, for instance, on two wildcat species.

Meanwhile, the US Fish and Wildlife Service recently issued its biological opinion for the third Brownsville area project, NextDecade's Rio Grande LNG project, as well as the related 135-mile Rio Bravo pipeline project. It found that the proposed project would not likely jeopardize the continued existence of the ocelot or the Gulf Coast jaguarondi, the two wildcat species in question.

It did not, however, consider the cumulative impacts of the other two LNG projects, saying those would be the subject of separate federal Endangered Species Act consultations.

Despite developers pushing for prompt action, FERC is being strongly urged not to do so by groups opposing the LNG projects.

Save RGV and Lower Rio Grande Valley Sierra Club Group on October 8 give FERC a series of reasons why FERC should deny the project or put off action on the 6.95 million mt/year Annova LNG project.

The group argued that FERC should redo the socioeconomic impact to take into account the October 1 approval of a property tax abatement for the project in Cameron County, Texas. The National Environmental Policy Act process "exists to accurately weigh the costs (social, environmental and economic) to benefits of technical wagers such as Annova's project," the filing said.

The groups also asserted the environmental review was incomplete and that action should wait until the deepening of the Brownsville Ship Channel is a "done deal" to allow for Annova's operations.

Unlike most LNG projects approved by FERC this year, the three Brownsville projects have faced robust opposition from a coalition of environmental groups, fishermen and a community organization.

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18 hours ago, James Regan said:

First sign of Madness would be a shiny brogue or ox blood Doc Martins (Currently walking around the room in a Ska fashion)

I saw The Beat recently Roger Rankin and his son Junior, fantastic.....

Screen Shot 2019-10-14 at 11.01.16.png

Ha ha Brilliant I wondered if you would get that, The Beat and the Selecter great bands I used to like all the old stuff from the 60s too.

Do I remember you saying you held Premier Oil, have you heard any whispers re Zama or Sealion recently ?

  • Upvote 1

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The U.S. could see its crude oil exports nearly double by 2022, according to energy research firm Rystad Energy.

Rystad forecasts that U.S. crude exports could increase from current levels of 2.9 million barrels per day (bpd) to nearly six million bpd by 2022. This is based off the nation’s expected production increase of 1.2 million bpd year-over-year in 2020 and domestic refineries at capacity to absorb shale growth.

“Crude exports will grow on the back of new infrastructure coming online in Corpus Christi, Texas, and as international crude buyers ramp up efforts to diversify their import sources after the attacks on oil facilities in Saudi Arabia and overall rising tensions in the Middle East,” said Paola Rodriguez-Masiu, a senior analyst on Rystad’s oil market team.

Rystad also noted the recent slowdown of U.S. crude exports in third quarter of 2019, due in part to the narrowing of the Brent-WTI price spread and effects from the five percent tariff imposed on U.S. crude by China.

Despite that slowdown, Rystad expects an export rebound to 3.7 million bpd in fourth quarter 2019 before climbing to even higher levels.

“This surge in crude shipments from the U.S. will be made possible by a flurry of new pipeline and export terminal infrastructure coming online in the coming years,” Rodriguez-Masiu said.




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South Korea's US crude imports double in Sep, Saudi shipments drop


South Korea's crude oil imports from the US in September more than doubled from a year earlier, while intakes of Saudi crude dropped 17.6% year on year due to the September 14 attacks on Saudi's major oil facilities, customs data showed Tuesday.



Customs data also showed the Asian country's intake of Iranian barrels remained at zero last month for a fifth straight month on Washington's sanctions.

South Korean refiners imported 1.62 million mt, or 11.87 million barrels, of US crude oil in September, compared with 5.11 million barrels a year earlier, according to the data.

The shipment made the US, South Korea's third-biggest crude supplier following Saudi Arabia and Kuwait.

The September shipments were also up 7.3%, compared with 11.06 million barrels imported in August.

The rise came after South Korea bought as much as 14.78 million barrels in July, the biggest volume since the country began US crude imports in 2015, breaking the previous record high of 13.61 million in December 2018.

The Asian nation's crude imports from the US have sharply increased since July last year when the Washington moved to re-impose sanctions on Iran which made South Korea buy more US crude to make up for the loss of Iranian barrels.

For the first nine months this year, South Korean imports of US crude soared more than three times to 97.94 million barrels, compared with 31.89 million barrels a year earlier, according to data compiled by S&P Global Platts.

The sharp increase was partly driven by more purchases of Eagle Ford condensate and DJ Common condensate as an alternative to Iran's South Pars condensate.

South Korean importers have also recently increased purchases of WTI Light and Eagle Ford Light and Medium as well as light sweet Bakken and WTI Midland ahead of the IMO 2020 marine fuel regulation, according to refiners.

South Korea's crude imports from Saudi Arabia dropped 17.6% year on year to 2.84 million mt, or 20.82 million barrels in September, from 25.26 million barrels a year earlier, according to the customs data.

The reduced shipments came after the attacks on Saudi Arabia's pivotal Abqaiq processing facility and Khurais oil field last month, which knocked out half of the kingdom's crude oil production.

Meanwhile, South Korea did not import any crude oil from Iran in September for a fifth straight month as waivers on US sanctions on Tehran expired early May.

In total, South Korea imported 10.48 million mt (76.82 million barrels or 2.56 million b/d) of crude oil in September, down 5.3% from 81.11 million barrels a year earlier.

Over January-September, South Korea's crude imports fell 3.1% year on year to 804.51 million barrels, down from 830.19 million barrels in the same period a year ago.

The September imports were down 20.9% from August imports of 97.07 million barrels.


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Shale-fueled US plastics boom puts spotlight on sustainability

Virgin plastic production is thriving in the US, fueled by the North American shale boom. But the reversal of fortune for the US chemical industry has highlighted a bigger challenge amid widespread concern about plastic waste and sustainability.

The growth of shale activity across the US unearthed ethane feedstock so cheap that a region that had been facing naphtha-fed plant shutdowns and petrochemical imports saw the cost advantage of home-fracked gas shaping its future as a global petrochemical supplier.


As such, the focus has overwhelmingly been on ethane-fed crackers and derivative polyethylene (PE), the resin used to make the most-used plastics in the world, and less on how to deal with the plastics they produce after use.

Companies are stepping up their efforts in recycled plastics, most notably with the Alliance to End Plastic Waste, to which dozens of companies have committed more than $1 billion to find solutions to the plastic waste problem.

While petrochemical giants like Dow, BASF, LyondellBasell, Sabic, Braskem, Sinopec, Sasol and Reliance Industries are among the alliance’s members, most efforts in the US focus on research and funding.

Production is still mainly virgin plastics, with inclusion of recycled resin in new plastic products being pushed by resin buyers.  And resin producers face the same key challenge as their counterparts in other regions, of sourcing enough high-quality plastic waste as a feedstock.

New ethylene, PE capacity

Fourteen new ethane crackers that are operational, under construction or planned from 2017 beyond 2020 will add nearly 18.5 million mt/year, or 52%, more US ethylene capacity, while 28 new PE plants starting up or planned in the same span will increase capacity by nearly 60%, or 13.67 million mt/year.

Other derivatives are accompanying some of the new crackers, such as monoethylene glycol or alcohols units, and a new polypropylene plant under construction. The companies that went all in on these projects include the biggest global names in petrochemicals: Dow, ExxonMobil, Chevron Phillips Chemical, LyondellBasell, Formosa Plastics USA, Sasol and Ineos.

US PET imports

The US is a net importer of PET, having received more than 2.2 million mt overall in 2018. Mexico was by far the top source, followed by Canada and Thailand.



Yet despite the growth in virgin plastic production, Indorama, one of the New Plastics Economy signatories, has been progressing in making recycling a key part of its future business model.

Indorama largely bypassed the cracker/polyethylene rush, except for refurbishing a long-mothballed Louisiana cracker to feed its own operations.

The world’s largest polyethylene terephthalate (PET) company instead doubled down on its forte, increasing its reach with the 100% recyclable and most-recycled plastic in the world used to make beverage bottles, polyester fibers and increasingly other plastics.

“All our customers are in touch with us and demanding that we improve and increase the recycling content in our PET. We’re allocating a budget of $1 billion to recycling so that by 2025, when the brand owners want 25% content in the packaging, [Indorama Ventures] would be able to deliver them,” said CEO Aloke Lohia, during an August conference call with investors.

The company has been actively making deals and forging partnerships aimed at increasing its own integrated recycling capabilities to provide recycled PET to customers who use it to make bottles, fibers and other products.

Those include its acquisition of Wellman International in 2011, which had two bottle washing facilities and a fiber plant that used recycled bottles flake as its primary feedstock.

The company has more recently added greenfield bottle washing capacities in Thailand and Mexico and acquired two other PET recycling companies: in 2018, Sorepla in France, and this year Custom Polymers in Alabama.

The Alabama facility processes post-consumer and post-industrial PET by grinding, washing and turning the plastic into pellets so it can be used as a feedstock for food-grade packaging and other end uses.

Closing the loop

Indorama also last year announced a joint venture with Canada’s Loop Industries to manufacture and commercialize sustainable polyester resin for beverage and consumer packaged goods companies.

The venture aims to “perpetually recycle” increasing amounts of PET plastic and polyester fiber, using Loop’s technology, with commercial production of 100% sustainably produced PET resin and polyester fiber targeted for the first quarter of 2020.

Lohia said during the August call that Indorama’s customers want PET to remain their main packaging choice, and the company sees more plastic packaging diverting to PET from other resins because PET is easier to recycle. For example, PET is being used to package more orange juice and make other non-beverage containers, like shampoo bottles, which would traditionally be made with polyethylene.

“That is good news for us. We just have to ensure we can deliver 25% recycled content,” he said.

For all these efforts, however, the US faces the same issue as Europe: collection rates.

Edmund Ingle, CEO of Indorama’s recycling segment, said that about 20 million mt of PET resin is sold into global packaging markets, and about 55% to 57% of that is recycled. In the US, the collection rate is much lower, about 28% to 30%, he said.

Ingle also said that in the next two to three years there will be a shortage of recycled PET due to a lack of extrusion and solid state polycondensation (SSP) capacity to turn PET flakes, which have been sorted, washed and ground from waste bottles, into recycled PET resin suitable for direct contact with food. Extrusion involves melting raw plastic, and SSP of PET flakes increases the weight of and purifies recycled PET so it can be used to make packaging for food and beverages.

Drinks bottles are commonly made from PET, but Indorama sees the plastic being used for more and more types of packaging due to ease of recycling.

Alpek, which owns US PET producer DAK Americas, is also working to increase its recycling capacity, under similar customer pressure to increase recycled PET content in its products. In the first quarter of 2019 Alpek acquired a 45,000 mt/year PET recycling plant in Indiana, adding to its fiber PET recycling operation in North Carolina and a food-grade PET recycling facility in Argentina.

However, Alpek CEO Jose de Jesus Valdez said during the company’s quarterly earnings call in July that the key for a circular economy is to improve the collection rate and ability to sell recycled PET at a price similar to that of virgin PET, which currently is significantly cheaper.

“A lot of bottles are not recovered, particularly in North America… Improving collection is going to be important so that we can increase our offer of recycled products,” he said.

Indorama has such technologies and is working to grow them. Ingle also noted that the cost of recycling remains a challenge, particularly with the poor quality of inputs from curbside collections. When that material is collected, it goes to a material recovery facility (MRF) to be sorted into different commodities, including PET, then baled and sold.

Some items cannot be recycled, such as small plastics like straws and packaging for mascara or toothbrushes that can get caught up in recycling machinery.

Plastic grocery bags can be recycled, as long as they are collected in bulk – a few tossed in a curbside bin can, like smaller plastics, get caught up in recycling equipment. Even PET bales made up of bottles that came from curbside bins can be of poor quality, Ingle said.

“However, the technology has advanced rapidly in the recent years, and allows companies with the latest equipment to sort more PET out of a bale, and thus improve yields and margins,” he said.

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ExxonMobil scouting for potential cracker site in Beaver County


ExxonMobil Corp. has been quietly scouting Beaver County for a suitable location to build a petrochemical plant that could pursue the same kinds of plastics manufacturing as Royal Dutch Shell's ethane cracker now under construction, multiple sources have told the Pittsburgh Business Times.

ExxonMobil (NYSE: XOM), one of the world's largest companies, is well-known as an oil producer, but it, like Royal Dutch Shell (NYSE: RDS.A) and other multinational oil and gas companies, also has a petrochemical division to convert fossil fuel byproducts like ethane and propane to plastics. Sources said that ExxonMobil has been looking at Appalachia for a potential petrochemical plant for the past three or four years, spurred by Shell's construction in Beaver County as well as other potential crackers by PTT Global Chemical in Belmont County, Ohio, and Braskem near Parkersburg, West Virginia.

Sources told the Business Times that while ExxonMobil seemed to have cooled on the plans since then, recently plans started heating up again. Brokers representing the company were in Beaver County last week, talking about a potential petrochemical plant to serve its customers.

One source familiar with ExxonMobil's search, a major land owner in the Beaver County area, said a broker offered the basic parameters of its site requirements in the region. Another source told the Business Times that at least one site in Beaver County had been visited.

ExxonMobil, one source said, seeks in the range of 240 acres along the river — land that's flat or can be made flat, with river access, with the need for environmental remediation of a site acceptable. The source indicated that ExxonMobil was working to narrow its options down to three sites — it's unclear whether all three sites are in Beaver County — and that it hopes to secure a site in the region by the end of the year.

It's likely that ExxonMobil would be looking at building a petrochemical plant along the lines of the Shell polyethylene facility in Potter Township. But a source said ExxonMobil may not use ethane as feedstock for its plant. There's also no guarantee that western Pennsylvania is the only potential location for Exxon; there are other sites in West Virginia and Ohio that also could host a petrochemical facility, including the Parkersburg site that Braskem recently pulled out of in West Virginia.




ExxonMobil didn't respond to a direct question on whether it had been looking in Beaver County.

"ExxonMobile continuously evaluates its global portfolio of businesses, depending upon fit with its overall strategic business objectives," an ExxonMobil spokeswoman emailed. "We have a range of existing and new petrochemical investments along the U.S. Gulf Coast. These are covered by ExxonMobile's Growing the Gulf initiative."

ExxonMobil in 2018 opened a 1.5 million-ton-a-year ethane cracker in Baytown, Texas, that is similar in size and scope to the ethane cracker that Shell Chemical Co. is building in Potter Township, Beaver County. And in June 2019, ExxonMobil and Saudi petrochemical company SABIC announced plans to build an even bigger ethane cracker in San Patricio County, Texas.

There's no guarantee that ExxonMobil will eventually build a petrochemical plant in Beaver County or elsewhere in Appalachia. But a multinational company taking another look at building a cracker here would be a big shot in the arm to a burgeoning petrochemical industry that got a home run with Shell's decision but hasn't yet gotten the follow-on investment that had been expected in the wake of the first cracker.

Shell's decision in June 2016 to go ahead in Beaver County led industry and economic development officials to market Appalachia in general and southwestern Pennsylvania in particular as prime for investment in the chemical industry. Local and state development officials have spent a lot of time trying to market a sometimes-wary petrochemical industry at the benefits of following Shell's lead. A 2017 IHS Markit study, commissioned by the Wolf administration and the TeamPA Foundation, estimated there's enough natural gas liquids to source four more plastics manufacturing plants in the region.


And the Trump administration has supported such plans, including considering a loan application by Appalachian Development Group to put a large-scale natural gas liquids storage facility and trading hub in either West Virginia, Ohio or Pennsylvania. That storage hub would be crucial to plans to build any more crackers because, while the ethane and propane are available, there needs to be a place to put it before use. Shell is using a long pipeline system for just-in-time manufacturing, with only three days of supply on hand when its cracker gets up and running early next decade. But most other crackers would need a storage system for the vast amount of raw material needed to feed a petrochemical plant.

Energy Secretary Rick Perry told the Business Times in August that there should be a strong petrochemical industry in Appalachia not only for economic development, but also protection from natural disasters along the hurricane-prone Gulf Coast where the major petrochemical plants are built.

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North America to spend $27bn on refining projects

Posted on Oct 16, 2019



Diversification into new revenue streams such as petrochemicals and export markets as refiners seek additional profit margins is keeping the short-term outlook for refining project spending healthy, according to an analysis by Industrial Information Resources (Industrial Info).



The North America refining project outlook has been healthy for some time and this trend looks set to continue in the near term.

Current active capex project pipeline projects at planning and engineering stage are estimated at $35 billion in North America, Industrial Info said.

Looking ahead, there will be some softening, but growth overall continues. 

North America Refining Projects Outlook

Looking ahead, North America could have up to $27.7 billion in refining projects with a kickoff start date of 2021 to 2022, Industrial Info said in its Global Refining Project Outlook presentation.

While grassroots spending represents 46% of the total projected spend, the project probability for these types remains low, Chris Paschall, Vice President of Research, Global Oil and Gas and Petroleum Refining said.

Of these, there are eight grassroots projects totaling $12.7 billion. One of these has already started site prep but still looking to secure final funds, Paschall said.

Crude diet flexibility to reduce feedstock costs is driving plant expansion activity, he said.

While spending to meet the ultra-low sulphur mandate has slowed down, compliance with the IMO 2020 regulation is spurring investments in coker and cat project announcements. 

Some projects related to IMO 2020 continue to be in construction or are even in the planning stage.

Nearly $7.5 billion of the projected $27.7 billion total would be for unit additions. These are projects adding brand new crude and auxiliary units at existing plants.

$2.5 billion would be plant expansions. This includes projects expanding capacity at both crude and auxiliary unit, plus the balance of the plant.

Other in-plant capex projects not adding any new capacity will total $2.5 billion as well.

Maintenance and turnaround projects are expected to total around 381 projects and valued at $2.5 billion as well. The maintenance forecast increases in 2020 over one year ago levels.

Reasons for investment

North America will continue to upgrade and improve existing infrastructure as it has the highest number of refineries of any region.

Midwest refiners’ margins are the healthiest of other regions because of the light, sweet crude processed in the U.S. which is cheaper than other types of crude, as well as higher prices earned for refined products.

West Texas Intermediate (WTI) oil has continued to outpace margins in other regions. In addition, U.S. refining margins remain high supported by tight product markets as a result of extended turnaround activity and unplanned outages earlier this year.

Singapore margins have recovered as a result of outages in the region but remain the worst performing of the global hubs. European cracking margins remain firm due to lower activity in the region.

Meanwhile in the U.S., there continues to be support for additional projects because gasoline and diesel demand remains stable and the export market is strong where a lot of U.S. Gulf Coast refiners are shipping into Latin America and some into Europe, Paschall said.

Demand outlook

Looking out farther toward 2030 to 2040, Industrial Info still sees refined product growing but in different areas. Gasoline demand will continue to increase in the short term with more autos on the road globally, but it starts to slow down around 2035 much slower rate.

Diesel demand continues to rise. More diesel vehicles will be on the road making this refined product a growth engine for the next 20 years.

Residual fuel oil demand will start to reverse. This is largely attributed to power plants switching to run on natural gas instead of bunker oil because of cost.

For now, U.S. gasoline demand set a record in July 2019; at 9.928 million bbl/day, which was the highest since 1991, Paschall noted.

Meanwhile, the U.S. continues to produce a lot of oil and exports about 3 million bbl/day and about 5 million bbl/day day of refined products. Exports into Latin America are expected to remain healthy.

Global refining projects outlook

North America is ranked fourth in terms of projected refining project spending behind various areas of Asia and Africa.

Western Asia has the highest ranking spend outlook at $78.2 billion which is attributed to growth in the Middle East. South Asia has the second highest spend outlook with $76.2 billion and Africa is the third highest with $75.8 billion in projects.

Grassroots spending remains dominant in the spending outlook, but Industrial Info expects this will slow down as worldwide global growth forecast projection drops.

More efficient vehicle fleets will continue to have an impact on gasoline demand in the future but will be offset by growth in the petrochemical and diesel markets.

Globally there are currently 653 projects under construction with a total investment value of more than $100 billion. This is down from more than 700 last year as project realization declines have been seen in Asia and Russia.

Projects continue to be announced but probability of all going through is unlikely as the supply-demand situation is becoming unbalanced.

Crude oil stocks rose by 7.4 mb/day May to 1,141 mb/day, the highest level since November 2017.

Global refining rates decreased by 0.7 mb/day in the second quarter of 2019 compared with a year earlier, the largest annual decline in over 10 years.

“I think the market will have a tough time absorbing a lot of this capacity that comes onto the market so I think a lot of these announced projects may have lower probability especially as you look further into the future. Even if some get started, there may be problems securing funding for completing these multi-billion-dollar projects,” Paschall said.

“Trying to get banks or even finance themselves could be challenging in this market. At the end of the day, we don’t need it (excess supply). Demand will not be robust enough to absorb all this (announced capacity),” Paschall said.

Industrial Info estimates there are more than 3,000 active projects at the planning or engineering stage for a kickoff of 2020-2021. These projects are valued at $274 billion.

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The U.S. Department of Energy (DOE) issued an order to Venture Global Plaquemines LNG LLC (Plaquemines LNG) approving exports of liquefied natural gas (LNG) from the Plaquemines LNG Project.  The project will be on the Mississippi River, in Plaquemines Parish, La., about 20 miles from the Port of New Orleans.

“The increase in LNG infrastructure projects in the U.S. has been astounding to watch,” said Secretary of Energy Rick Perry in a statement. “Projects like Venture Global’s Plaquemines create well-paid, American jobs and have changed the game in sharing the benefits of U.S. LNG with our allies around the world. I am glad the Department is doing our part to empower the Plaquemines project and other energy infrastructure to progress quickly.” 

Under the order, Plaquemines LNG will be able to export up to 3.4 billion cubic feet per day (Bcfd) of LNG from the project by ocean-going vessel to any country with which the U.S. does not have a free trade agreement, and with which trade is not prohibited by U.S. law or policy.

The Federal Energy Regulatory Commission (FERC) authorized Plaquemines LNG to site, construct, and operate the Plaquemines LNG Project in Sept. 2019.

Along with the announcement, the DOE has also approved 38.06 Bcfd of LNG exports LNG and compressed natural gas to non-FTA countries. Of this amount, about 15 Bcfd of export capacity is in various stages of operation and construction across eight large-scale export projects. Venture Global’s Calcasieu Pass project is currently under construction.

The U.S. is the top natural gas producer globally and is currently producing about 92 Bcfd of natural gas. LNG exports from the country recently reached 5 Bcfd.

The Venture Global Plaquemines LNG, LLC order can be found here.

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Kinder Morgan to have all Elba Island LNG units in service by mid-2020 -CEO

Kinder Morgan Inc expects to bring the remaining nine units of its liquefied natural gas (LNG) export facility at Elba Island into service by the first half of next year, Chief Executive Officer Steven Kean said on Wednesday.

The first unit of Kinder Morgan's Elba Island facility began producing LNG natural gas for export last month, and is one of several new U.S. projects adding to global supplies.

The Houston pipeline operator plans to bring three more into service this year, with another six to start up in the first half of 2020, Kean told investors on an earnings call.

The facility has experienced periodic delays since late last year, which had been "a drag on our financial performance," Kean said. The company expects to end 2019 with adjusted pre-tax earnings 3% below its budget, with the delays contributing to the variance, Chief Financial Officer David Michaels said.

The Federal Energy Regulatory Commission (FERC) approved Kinder Morgan's request to begin LNG production and exports in a filing dated Sept. 30.

In Texas, commercial activity to develop a 2 billion cubic feet per day (bcfd) natural gas pipeline project in the Permian Basin, the largest U.S. oil field, has slowed, because of "some producer retrenchment in their Permian activities," Kean said.

"We believe the pipeline is needed, but it may not be needed quite as soon as we were expecting 3 months ago," he said.

The company brought its Gulf Coast Express pipeline, of the same size, into service last month, slightly ahead of schedule. The Permian Basin has long needed additional gas takeaway capacity as output overwhelmed pipeline space needed to transport the gas out the region, in West Texas and New Mexico.

Three other gas pipeline projects with capacity of 2 bcfd are slated to come online from 2019 to 2021, and the Permian Pass pipeline "may not be needed in 2022," Kean said.



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Oil production from the seven heavy-hitting U.S. shale plays could reach 8.971 million barrels per day in November, (a month on month increase of 58,000 bpd), according to the Energy Information Administration’s latest Drilling Productivity Report.

Most of the production jump will be thanks to the Permian Basin, which is expected to see a production bump of 63,000 bpd next month. In October the Permian is on track to produce about 4.547 million bpd of crude, quite a bit more than the other six plays.





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USGC crude exports flowing despite 128% VLCC freight spike



Total volumes of US-origin crude exports are expected to see minimal impacts from spike in US Gulf Coast-loading VLCC freight rates of more than 128% since September 25, as a combination of geopolitical and pre-IMO 2020 factors reduced the VLCCs fleet capacity by 15%.


Marginalized VLCC tonnage includes 42 COSCO units following US sanctions on two affiliates of COSCO Shipping Co. and 38 VLCCs owned by the National Iranian Tanker Company, an S&P Global Platts Analytics Spotlight report showed Monday. It also includes 24 VLCCs currently used for floating storage of low-sulfur bunkers or low-sulfur blending components to facilitate the switchover from 3.5% sulfur to 0.5% sulfur bunkers by January 2020, and 20 units currently dry docked for scrubber installations ahead of the IMO 2020 deadline.

Yet, the initial spark that fueled the pre-IMO 2020 storm were the US sanctions on tonnage of COSCO Shipping Tanker (Dalian) and COSCO Shipping Tanker (Dalian) Seaman & Ship Management Co., which sent the cost of taking VLCCs out of the USGC to unprecedented highs over the past two weeks.

S&P Global Platts on Tuesday assessed freight for the key VLCC 270,000 mt USGC-China route at lump sum $18 million, up 128% from September 25 -- the day before the sanctions news emerged -- after peaking at $21 million on Monday.

The arbitrage window for bringing US-origin crude into Asia Pacific markets remains adamantly shut since VLCC freight hit $20 million on October 11, Platts Analytics data showed. Arbitrage opportunities for other key crude grades such as West Africa-loading Bonny Light and Persian Gulf-loading Murban also remain firmly shut.

"If freight rates stay this high then US crude prices will have to fall," Sandy Fielden, Director, Oil Research, Morningstar Commodity Research, said last Thursday at the Crude Oil Quality Association conference in Dallas. "No one is going to buy crude that is more expensive than what is available in their immediate region. It's a world market and the only way for us to compete is through price."

The economics of taking US-origin crude will have to adjust to keep export barrels moving, likely leaving FOB prices to absorb the increase in freight, according to Platts Analytics.

"Likely you won't see traders coming to the market to take ships but the SK Energy, Oxy [Occidental], and HOB [Hyundai Oilbank] system guys will still need to take ships," a shipbroker said.

Volatility in the freight market has impacted most exported crudes around the world and the US grades are no exception. WTI FOB cargoes along the US Gulf Coast have plunged lower during the past week and were assessed Tuesday at a $2.83/b discount to the Dated Brent strip and a $2.40/b premium to the WTI NYMEX strip, which reflects a 15-45 day loading window. That is compared with the differential's high this year of WTI NYMEX strip plus $8.80/b, which was reached on May 28.

A majority of the exports that occurred last week were booked more than a month ago, when freight rates were much lower. New long-haul pipelines are bringing more light sweet crude from the Permian Basin to the US Gulf Coast and many of those barrels must be exported, which puts added pressure on the export market.

US crude oil exports rose by nearly 535,000 b/d for the week ended October 4, to reach over 3.4 million b/d, which was their highest level in about eight months, according to data released October 9 by the US Energy Information Administration.

Some crude traders expect to see some decline in US crude export volume as spot FOB cargoes are facing difficult pricing dynamics. However, delivered cargoes and contract deals will continue to keep exports flowing.


Industry participants are left questioning the sustainability of the rally, attempting to predict the day when market fundamentals will take a bearish turn. "It's going to take a while I think," a shipbroker said.

A cocktail of events have driven bullish sentiment in the VLCC market heading into the third quarter and the fourth quarter of 2019, including a reduction in fleet utilization in the spot market from Iran sanctions and IMO 2020 preparations as well as an overall uptick in crude exports moving out of the USGC on VLCCs.

Looking at the overall global VLCC fleet, which contains 792 ships worldwide, according to Platts Analytics, the combined events of the past year have led to a reduction of about 124 units or 15% of the fleet size available to the spot market, not counting the ships that could be affected by potential secondary sanctions on Venezuela.

The Forward Freight Agreement market would suggest rates for the USGC-China route to stay in the double digits at least moving into the next month, with the November contract for the 270,000 mt USGC-China route last traded at $44/mt, or a lump-sum equivalent of $11.88 million.


There is a possibility of an increased number of US-origin crude exports being diverted to Europe to avoid major costs on the typically Asia-destined VLCCs, however firming in the VLCC segments has begun to trickle down into smaller tonnaged ships.

The arbitrage for bringing WTI crude into Europe is open at 82 cents/b compared to UK origin Forties crude.

Long-haul Suezmax rates have reached rates seen by VLCCs less than two weeks ago, with the 130,000 mt USGC-Singapore route last assessed Tuesday at lump sum $9 million. On the trans-Atlantic front, rates have been slower to rise with the times as owners are more willing to make the shorter voyage to Europe, with anticipation of capitalizing on a bullish market instead of taking their ships out of the market for extended periods of time.

The cost of taking a Suezmax on a 145,000 mt USGC-UK Continent run was last assessed Tuesday at w180, or $32.18/mt, up 177% from the average rate for September.

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A&R Logistics to build new resin export facilities on US East Coast



A&R Logistics is planning new export facilities at two US East Coast ports as US polyethylene production and exports grow, the Houston-area resin logistics company said Tuesday.


The company plans to open a new export facility at the Port of Savannah in Georgia late next year with initial ability to package up to 43,091 mt/month. The 2 million square-foot facility will be able to expand packaging capacity to 172,365 mt/month.

The announcement came a week after the company said it also will open a 1 million mt/year new resin packaging facility near the Port of Charleston in South Carolina as well that will start up in the fourth quarter of 2020.

That facility will start with packaging capacity of 43,091 mt/month, with ability to expand to 86,182 mt/month.

The US is adding more than 13.67 million mt/year of new polyethylene production capacity from 2017 through the 2020s. Nearly 34% of that new capacity, or 4.63 million mt/year, is operational, with another 1.77 million mt/year slated to start up by year's end.

The vast majority of US polyethylene exports ship out of the Port of Houston, the second-largest petrochemical port in the world behind Rotterdam, largely because most of the new production sits along or near the Houston Ship Channel.

However ports in Charleston and Savannah, as well as New Orleans and Los Angeles, have marketed themselves as alternatives to Houston. All five are seeing sharp growth in PE exports.

According to US International Trade Commission data, 1.47 million mt of PE shipped out of Houston in the first half of 2019, up 58% from the January-June period of 2018. New Orleans shipped out nearly 192,000 mt over the same period this year, more than triple the amount exported from the port in the first half of 2018, which moved the port to second place from third.

Charleston moved out 134,329 mt in the January-June period this year, nearly triple the 46,005 shipped out in the first half of 2018, moving that port to third place from fourth last year. Los Angeles fell to fourth place in the first half of this year from second place in the year-ago period, just behind Charleston with 134,017 mt in PE exports, though volumes shipped out increased through June this year by 21%.

Though Savannah moved out the least of the five in the first half of this year, its exports of 47,269 mt was 13 times higher than 3,450 mt exported in the January-June period of 2018.

A&R has a smaller PE export facility at the Port of Savannah, with a capacity of up to 12,927 mt/month, and had been seen as a test site.

The company also said on Tuesday that it will open its global export division headquarters at the Port of Savannah as well, "to support global supply chain development for the chemical industry."

Polyethylene is used to make the world's most-used plastics, such as milk jugs, grocery bags, shampoo bottles, food packaging and wrap.

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Technology takes over tight oil

As the shale business matures, its wildcatter mentality is being replaced by artificial intelligence

A WTI crude price rangebound in the $50-$60/bl band means profitability is under pressure across the US shale business, which faces far higher ongoing opex than operators of conventional resources. WTI at $100/bl can support a fragmented market of hundreds of participants but lower prices require savings to be squeezed from economies of scale and the innovative application of new technology. 


Disappointing returns have largely locked small players out of capital markets and the recent trend is solidly towards consolidation, with the majors becoming increasingly interested in taking stakes when they are available at the right price. Occidental, which purchased Anadarko and kept its US shale assets, is at the forefront of these shifting dynamics as it operates the largest number of shale wells, 25,000, and participates in a further 100,000. 

While the specifics of geography, scale, total acreage and the supply chain are all important factors, “technology and datasets provide a whole host of things to make it work from a returns perspective,” says Oscar Brown, senior vice president, strategy, business development and integrated supply at Occidental.

The firm’s proprietary technology, Oxy Drilling Dynamics, is being applied to the wells it gained from its acquisition. “A lot of the real-time decisions made by the driller are becoming automated. It takes the bias out. It is the whole workstream that is different, not just the technology,” says Brown.

“One thing that is hard to do in any area—certainly in unconventionals—is to know where your [drill] bit is. The bits are under a lot of temperature pressure and that is hard on the sensors. We take the visible data from across the face and our geo-mechanic understanding of the different layers of rocks and run all that into algorithms, and then test it against our database and the real world.”

Scraping the barrel

The spectacular growth rates of 2013 are unlikely to be repeated so the focus has shifted to extracting more from each well. The challenge of extracting 1.5mn bl/d oe in 2013 from the big-three US shale basins—Eagle Ford, Bakken and Permian—is entirely different to extracting 7mn bl/d oe in 2019, notes Greg Leveille, chief technology officer at US independent ConocoPhillips. “When you look at what is behind that enormous growth, it is really a lot of engineering and science.”

While he estimates that recovery factors for unconventional liquids are 5-10pc and natural gas 10-20pc, “at Eagle Ford, our single biggest asset, we're getting a 20pc recovery factor from a liquids-rich play,” says Leveille. “We have been able to do that by looking at the completion design, the spacing and stacking of the wells—so-called parent-child relationships—and how we use refrack as a tool.”

“It is an incredible opportunity because, if you can find ways to develop automation or artificial intelligence to improve the costs of an unconventional well, you can apply it to literally thousands or tens of thousands of wells” Leveille, ConocoPhillips

“If you do the right things” in parent-child wells the reserve numbers do not change, he adds. “A lot of that has to do with innovation and technology advancements… as you are in-filling the development of your field you can get not only excellent production volumes from your new wells but actually increase the volumes in the old wells.”

Steadily increasing international oil company (IOC) involvement “certainly” signals maturity and capital discipline, says David Turk, head of the strategic initiatives office at the IEA. “There has been phenomenal technological progress,” adding that “there are areas of technology being explored right now that could be quite impactful”, but Turk would be surprised if the pace of technological progress can be maintained.

“Certainly, [enhanced oil recovery] is interesting and refracking is an area where we are getting interesting numbers. Digitalisation is impacting a lot of parts of oil and energy—whether it's AI-enabled horizontal drilling or using other tools and techniques—especially when the IOCs get involved.”

Digital enhancement

Plateauing productivity rates are reportedly prevalent across the shale sector but certain operators are breaking out of the constraints. “We are still seeing a lot of improvements year-on-year,” according to ConocoPhillips’ Leveille. 

“The ones we are really excited about have to do with digitalisation impacting the way we drill wells. It is an incredible opportunity because, if you can find ways to develop automation or artificial intelligence to improve the costs of an unconventional well, you can apply it to literally thousands or tens of thousands of wells. It is a big, big prize. We are looking at automated drilling and a lot of other things for how we run the oil patch.” 

The industry is drilling tens of thousands of wells a year in the US so the task has multiplied in complexity. “You cannot run those fields the same way you would have run them in the past, which was very focused on manpower. We see an enormous amount of automation coming and reducing both capital and operating costs is going to be impactful. We are still finding ways to increase productivity.”

The environmental impact of unconventional oil and gas production have been tracked for a decade. “Over time, the performance of the industry and state regulators has significantly improved. Induced seismicity was a huge issue a few years ago,” says Robert Kleinberg, senior research scholar at the center on global energy policy at Columbia University.

He notes that US-based National Academy of Sciences research detailed how engineering controls and monitoring can significantly reduce seismicity. “That was implemented by the industry and state regulators working together and now that problem is largely in the rear-view mirror,” says Kleinberg.

While the shale boom has transformed the US into the world’s largest producer, the practice is notable by its absence elsewhere in the world, despite some similarly attractive geological formations. “In the US we have 9,000 producers, all of which operate on relatively small margins, have small leases and generally—except Occidental and ConocoPhillips—have small resource bases,” says Kleinberg. 

“In the rest of the world, the industry is dominated by IOCs and [national oil companies] with large inventories of fossil fuel resources. They will always exploit the cheapest resources first and, ex-US, tight oil and shale gas are not the cheapest resources in their inventories.”

Shale technology still has a long way to develop and it is going to require a lot more integration, engineering and data science, according to Leveille “That is going to set the playing field for companies which have the size and scale to bring all types of expertise to bear. This year, we are seeing a big differentiation between the companies with both good acreage and capabilities and other companies that do not have all these elements. I am not surprised rig counts are going down—from our perspective that reflects the future of the industry.”

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Questions of science – challenging our tight oil forecasts




4 reasons we’re bullish on Exxon’s Permian growth campaign


07 October 2019



Permian operators cash in ... by thinking inside the box

Cube developments offer players option to optimise output and costs


Up for the challenge? Supermajors' new aggressive Permian targets


06 March 2019





While smaller E&Ps are being forced to tap the breaks in the Permian shale basin, Exxon and Chevron have laid out ambitious production targets for the next four to five years:

·         Chevron: 900,000 boe/d in 2023

·         Exxon: 1 million boe/d by 2024


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