National Oil Corporation (NOC) confirms the return of production at the Sharara oil field south of the country, after lengthy negotiations by the NOC to reopen the Hamada valve, which had been illegally closed last January- resulting in the shutdown of production and collapse of the tank (Surge Tank D101 B), whose capacity is 16,000 barrels and is situated in area (GOSP115) at the field, after an armed militia prevented NOC’s maintenance teams from carrying out maintenance operations.

NOC chairman, Eng. Mustafa Sanalla, commented: “The Libyan economy has suffered enough from the illegal blockades and We have much to do, and we hope that the restart of production at the Sharara oil field will be a first step to reviving the Libyan oil and gas sector and preventing an economic collapse in Libya in these difficult times”.

The first production phase will start at a capacity of 30,000 barrels/day. Production at the field is expected to return to full capacity within 90 days due to the damages resulted by very long shutdown.

The illegal blockade for a period of 142 days cost the public treasury losses estimated at about USD 5,269,251,172.00 billion

https://noc.ly/index.php/en/new-4/5969-noc-confirms-restart-of-production-at-sharara-oil-field&ct=ga&cd=CAIyHGUzNTNmYzI0N2YyZGM3ODQ6Y28udWs6ZW46R0I&usg=AFQjCNEvFdlO4cjNiIF_m29pEGNcz0Jpm

Saudi Aramco on Sunday raised the price at which it will sell oil to all global markets in July, after the Riyadh-led Organization of the Petroleum Exporting Countries agreed with its allies on Saturday to extend historic price cuts through the month of July.

State-run Saudi Arabian Oil Co. raised the official selling price of all grades of crude sold to the Far East in July, raising the July price for its Arab light crude oil to Asia by $6.10 a barrel from June to a 20 cents-a-barrel premium to the Oman/Dubai average.

Aramco also increased the price of super-light crude-oil by $7.30 a barrel, shifting its price from a discount to a $1.65-a-barrel premium to the Oman/Dubai average. With higher quality light grades of crude oil tending to be used in the production of jet fuel and gasoline, the move is a signal that Far East Asian oil demand is beginning to recover from the worst effects of coronavirus lockdowns.

In the wake of a demand-damaging coronavirus pandemic and a vertiginous price rout during April, the 23-nation alliance of OPEC and its allies agreed earlier this week to continue their efforts at rebalancing a global oil market in the early stages of recovery.

Led by Saudi Arabia and Russia, the cartel agreed in April to cut output by 9.7 million barrels a day, withholding some 13% of supply from the global oil market and elected this week to continue those cuts through the end of July before reducing them.

Oil prices have rallied over recent weeks amid the beginnings of a pickup in demand for oil and oil products as some regions have emerged from lockdown, and ahead of the widely-expected supply cut extension.

Analysts expect that the longer cuts will speed up the rebalancing of global oil supply and demand. In that vein, Aramco also increased all of its selling prices to the U.S., North West Europe, and the Mediterranean. In each of those reasons, the company increased its light crude prices by 60 cents a barrel, $4 a barrel, and $4.70 a barrel, respectively.

"The 9.7 million barrel-a-day production cuts were already working, extending them an extra month will tighten the market more quickly," said Ann-Louise Hittle, vice president of macro oils at consulting firm Wood Mackenzie, after OPEC's decision.

"The fundamentals show the oil market is recovering from March's price shock. Supply has shifted dramatically...[and] global demand is recovering too, with both May and June climbing from the low seen in April as the coronavirus-related shutdowns continue to ease," she added.

https://www.marketscreener.com/SAUDI-ARABIAN-OIL-COMPANY-103505448/news/Saudi-Aramco-Raises-July-Crude-Official-Selling-Price-to-Asia-30737333/&ct=ga&cd=CAIyHGMzMDI4NGM4N2E3MjhhZTM6Y28udWs6ZW46R0I&usg=AFQjCNGuZJigLFN2FWuhRqKNrwKDQ2DCB

OPEC and allied nations agreed Saturday to extend a production cut of nearly 10 million barrels of oil a day through the end of July, hoping to encourage stability in energy markets hard hit by the coronavirus-induced global economic crisis.

Ministers of the cartel and outside nations led by Russia met via video conference to adopt the measure, aimed at cutting the excess production depressing prices as global aviation remains largely grounded due to the pandemic. The curbed output represents some 10% of the world's overall supply.

But danger still lurks for the market, even as a number of nations ease virus-related lockdowns, and enforcing compliance remains thorny.

Algerian Oil Minister Mohamed Arkab, the current OPEC president, warned meeting attendees that the global oil inventory would soar to 1.5 billion barrels by the mid-point of this year.

“Despite the progress to date, we cannot afford to rest on our laurels,” Arkab said. “The challenges we face remain daunting.”

That was a message echoed by Saudi Oil Minister Abdulaziz bin Salman, who acknowledged “we all have made sacrifices to make it where we are today.” He said he remained shocked by the day in April when U.S. oil futures plunged below zero.

“There are encouraging signs we are over the worst,” he said.

Russian Energy Minister Alexander Novak similarly called April “the worst month in history” for the global oil market.

The decision came in a unanimous vote, Energy Minister Suhail al-Mazrouei of the United Arab Emirates wrote on Twitter. He called it “a courageous decision.”

But it is only a one-month extension of a production cut that was deep enough “to keep prices from going so low that it creates global financial risk but not enough to make prices very high, which would be a burden to consumers in a recessionary time,” said Amy Myers Jaffe, senior fellow at the Council for Foreign Relations.

“There is so much uncertainty that I think they took a conservative approach," she said. “You don’t know how much production is going to come back on. You don’t know what’s going to happen with demand. You don’t know if there’s going to be a second (pandemic) wave."

Jaffe said improved oil demand in China and Asia and a gradual stabilization of demand in the United States and to some extent Europe, where there's some cautious economic reopening, were encouraging for producers.

OPEC has 13 member states and is largely dominated by oil-rich Saudi Arabia. The additional countries involved part in the so-called OPEC Plus accord have been led by Russia, with Mexico under President Andrés Manuel López Obrador playing a considerable role at the last minute in the initial agreement.

Crude oil prices have been gaining in recent days, in part on hopes OPEC would continue the cut. International benchmark Brent crude traded Saturday at over $42 a barrel. Brent had crashed below $20 a barrel in April.

Earlier this year, when demand was down, Saudi Arabia was flooding the market with crude oil, helping to send prices down to record lows. That prompted the U.S. government in April to take the unusual step of getting involved in OPEC’s negotiations, pressuring members of the cartel to agree to cuts to help end the oil price free-fall.

At the time, President Donald Trump said the U.S. would help take on some of the cuts that Mexico was unwilling to make. And perhaps more importantly, a group of U.S. senators upset over the impact on U.S. shale production said at the time that they had drafted legislation which would remove American forces, including Patriot Missile batteries, from Saudi Arabia.

Under a deal reached in April, OPEC and allied countries were to cut nearly 10 million barrels per day until July, then 8 million barrels per day through the end of the year, and 6 million a day for 16 months beginning in 2021.

In a rambling Rose Garden speech on Friday, Trump took credit for the April deal. “People said that wasn’t possible but we got Saudi Arabia, Russia and others to cut back substantially,” he said. “We appreciate that very much.”

U.S. Energy Secretary Dan Brouillette tweeted his applause Saturday for the extension, which he said comes “at a pivotal time as oil demand continues to recover and economies reopen around the world.”

However, some countries have been producing beyond quotas set by the deal. One was Iraq, which remains decimated after a years-long war against the Islamic State group. Iraq Oil Ministry spokesman Assem Jihad said in a statement that Baghdad had “renewed its full commitment” to the OPEC Plus deal.

Analysts had expected only a one-month extension given the still fluctuating level of demand.

“If the demand is great, countries like Russia will want to produce more oil, so they probably won’t want to get locked into a longer-term deal that may not help them,” said Jacques Rousseau, managing director at Clearview Energy Partners.

In a research note, Clearview also said Saturday that the producers group "appears to be going to great lengths to keep the deal together despite unequal compliance” — trying to avoid public fights on the issue.

“That solution might work today, but not repeatedly,” it said, citing reports of rising Libyan output and the end of production cuts from Mexico that will heighten the need for compliance.

Major production cuts are simply untenable for countries such as Iraq, Oman and Ecuador, whose economies depend nearly exclusively on petroleum income, as they could face debt default.

https://japantoday.com/category/world/opec-allied-nations-extend-nearly-10m-barrel-cut-by-a-month?utm_source=twitter&utm_medium=referral&utm_campaign=dlvr.it

Tokyo — Japan's largest refiner JXTG Nippon Oil & Energy said June 8 it will supplement any shortfall in July term crude oil requirements as a result of the near 10 million b/d OPEC+ production cut extension by purchasing cargoes from the spot market.

"Even in the event of facing supply cuts from our direct term contracts, we intend to procure our crude requirements from spot markets so that we do not foresee a major obstacle," a company spokesman told S&P Global Platts.

Japan sources roughly 90% of its crude imports from the Middle East, of which 70%-80% of the supplies are based on term contracts.

OPEC and its allies have agreed to maintain their record oil cuts through July -- albeit without Mexico -- to help steer the market through its nascent recovery from the coronavirus pandemic.

Ministers on June 6 approved a one-month rollover of their now 9.6 million b/d production cut accord, brushing aside Mexico's defection from the pact and receiving pledges of improved compliance from Iraq, Nigeria, Angola and Kazakhstan. The cuts -- originally 9.7 million b/d including Mexico -- had been scheduled to taper to 7.7 million b/d in July through the rest of the year.

For June loadings, Japanese refiners have received "larger-than-expected cuts" to their term crude supply from OPEC producers, keeping them balanced against plummeting domestic demand due to the coronavirus pandemic, Tsutomu Sugimori, president of the Petroleum Association of Japan, said May 22.

Saudi Aramco has informed at least one Japanese refiner that it will reduce its June-loading crude allocations by 20%-40%, with the cuts being made across all grades and larger cuts to heavier grades.

Demand recovery

Japan's gasoline demand has shown some recovery in recent weeks, following the lifting of the state of emergency on May 25 after bottoming out during the Golden Week national holidays over late April to early May.

The domestic gasoline shipments were estimated at 4.68 million barrels for the week over May 24-30, up 11% from the previous week, according to S&P Global Platts calculations based on the PAJ data.

The estimated May 24-30 gasoline shipments recovered to 4.72 million barrels over April 5-11, almost around the same level prior to the state of emergency, which was imposed on April 7.

Asked whether JXTG would consider importing gasoline beyond July during Japan's demand season amid signs of a gasoline demand recovery, the spokesman said: "We have a system in place to ensure stable supply for any fluctuations in demand."

Japan's spot gasoline price has also turned to an upward trend in recent weeks amid rising crude prices, coupled with demand recoveries during weekends amid tight domestic production.

"After the lifting [of the state of emergency], our [gasoline] demand improves about 10% from the worst as our weekend sales slightly increased," said a Japanese trader.

Another Japanese trader said: "The recovery is still on the way as the [overall] demand remains weaker than before but we are increasingly seeing more orders [for sales]."

As of June 8, Japan's domestic gasoline rack prices in Chiba, east of Tokyo Bay, stood at Yen 36,600/kiloliter ($53.15/b), up 30.2% or Yen 8,500/kiloliter from May 25 when the state of emergency was lifted, Platts data showed.

Japan's crude throughput dropped 7.7% week on week to 1.82 million b/d over May 24-30, with its refinery utilization rate falling to just 51.8% of the 3.5188 million b/d capacity, the Petroleum Association of Japan said June 3.

http://plts.co/61rl50A1wO1

SINGAPORE (Bloomberg) --Oil traded near $42 a barrel in London after OPEC and its allies agreed to extend historic output curbs by an extra month, but Saudi Arabia signaled it wouldn’t continue with additional, deeper curbs after June.

Brent futures were little changed, after rising as much as 2.6% in earlier trading. OPEC+ agreed over the weekend to extend record output curbs. Saudi Arabia -- which had curtailed output by more than its agreed quota -- said at a press conference Monday that those extra reductions will last just one month as planned, as the measures have served their purpose.

The extension of the existing limits is a victory for Saudi Arabia and Russia, which were deadlocked in a brutal price war just two months ago. OPEC+’s de-facto leaders showed their commitment to shore up oil markets globally, and even cajoled Iraq, Nigeria and other laggards to fulfill their promises to reduce production. Following the meeting, OPEC’s largest producer sharply hiked its official selling prices.

The supply cuts and a rebound in demand have helped oil prices double since April. China’s crude imports surged to a record high last month, while consumption in other major economies such as India is improving. Still, a sustained rebound in prices may be hampered by deteriorating relations between Washington and Beijing, a second wave of infections, or returning U.S. shale supply.

Prices

- Brent for August settlement fell 1 cent to $42.29 a barrel as of 12:47 p.m. London time

- Brent for August settlement fell 1 cent to $42.29 a barrel as of 12:47 p.m. London time Based on Brent’s relative strength index, oil is sitting in overbought territory and due for a decline

- Based on Brent’s relative strength index, oil is sitting in overbought territory and due for a decline West Texas Intermediate for July delivery fell 0.7% to $39.28

- West Texas Intermediate for July delivery fell 0.7% to $39.28 The WTI strip for 2021 was at $41.29, the highest since March

Following the new deal, Saudi Arabia pressed on by increasing some crude prices by the most in at least two decades. The hikes erased almost all of the discounts the kingdom made during its brief price war with Russia, with the steepest increases hitting July exports to Asia.

As OPEC met virtually over the weekend, Tropical Storm Cristobal was swirling over the Gulf of Mexico. Offshore drillers idled about a third of oil production, amounting to about 636,000 barrels of daily output, due to the storm, according to the Bureau of Safety and Environmental Enforcement. The storm has now crossed the coast.

Meanwhile, Libya’s biggest oil fields are gradually resuming production after a five-month shutdown due to civil war. Output will start at an initial 30,000 barrels a day at Sharara and it will take three months to return to full capacity, according to National Oil Corp. Supply from El-Feel also restarted on Sunday, according to a person with direct knowledge of the situation.

http://ow.ly/BmCH50A1Cwu

The coronavirus pandemic and the unprecedented plunge in energy demand has forced oil companies to shut down wells by the thousands, providing another test for a shale industry that restored the U.S. as a leading global producer and spurred Houston’s economy for more than a decade.

Well shut-ins, as the closings are known, have never occurred on this scale during the shale industry’s short history, and that has sparked a debate over how — and if — shale drilling will recover from the oil crash. No one knows for sure what happens to a shale well when the spigot is turned off for several months or longer, raising the question of whether oil will flow freely again when wells are restarted or fizzle out like a bottle of stale soda.

The result will determine how quickly U.S. oil production and local economies that depend on it rebound from the steep downturn that has battered energy companies, bankrupted some and cost thousands of jobs. If shale output languishes when demand ramps up, the American oil industry could lose out on market share and money while oil-focused economies such as Houston’s surrender investment and employment.

“We’re in uncharted territory,” said Matthew Fitzsimmons, vice president of energy research at Norway-based Rystad Energy. “Operators can use downhole sensors to make an educated guess, but it’s going to be hard to tell. The truth is going to come out when they turn it back on.”

Operators that shut down rigs run several risks: Valves and well parts could corrode, allowing water and other sediment to enter the well shaft. The well also could lose pressure and the oil could move to a different part of the reservoir, lowering the expected total output.

“If you don’t protect the well integrity and pressure of the reservoir, the decline curve will be even more steep,” Fitzsimmons said, referring to the naturally declining lifespan of shale wells. “Pressure could be down so you don’t get the peak. You don’t get as much oil as you had expected.”

Not everyone in the industry believes there is a risk involved with shutting in wells. Several energy companies, including Continental Resources and Pioneer Energy Resources, have gone on the record saying they don’t expect any damage from shutting in wells.

“I think the statement of great risk and economic damage to wells is overblown,” said Ed Hirs, a petroleum economist with the University of Houston. “They’re temporarily closing off the valve. Wells come back pretty easily, especially oil wells. The real challenge is the loss of revenue. That’s the part that hurts.”

The energy industry has already slashed production by shutting down existing rigs, postponing well completions and cutting back on new wells.

Last week the number of operating rigs in the nation dipped below 300 for the first time, down 70 percent from a year ago, according to Baker Hughes. Meanwhile, domestic crude production is expected to tumble to 11.7 million barrels a day in 2020, down from 12.2 million in 2019, according to the Energy Information Administration.

But tallying up the number of shut-ins is more difficult. Rystad, however, estimates that the figure is well into the thousands.

‘The easy part’

Shutting in a well, simply put, involves going out to a wellhead and turning off some pumps and valves, flushing equipment with cleansing agent nitrogen, applying anti-corrosion treatments and securing the property. The process can take less than a day to complete.

Exploration and production companies usually hire oil field service firms to shut in wells. Typically, older, lower-margin wells are shut in first before more productive wells.

Halliburton, a Houston oil field service firm, said it has long offered specific shut-in services, such as protecting an electric submersible pump, but in recent months has provided more comprehensive well diagnostics and consultations for a successful restart. The company’s goal is to balance shutting the wells at the lowest possible cost while preventing any well or reservoir damage that could affect its long-term productivity.

“Shutting in wells is the easy part,” said Shannon Slocum, Halliburton’s senior vice president of global business development and marketing. “The question is how to bring these wells back to their production level after shut-in.”

The risk of damage increases the longer a well is shut in, according to Wood Mackenzie, a U.K.-based energy research firm.

“Routine short-term shut ins — days to weeks — for maintenance seem to cause few reservoir problems,” Wood Mackenzie said in a recent report. “But widespread shut in of tight-oil horizontal wells is rare, so the long-term reservoir response is uncertain.”

Avoiding surprises

Energy companies are split on the impact shut-ins could have on shale wells.

Apache has shut in around 2,500 wells nationally in response to the oil bust. Clay Bretches, the Houston oil and gas producer’s executive vice president of operations, said the company is focused on preserving its wells, surface equipment and tanks so that when oil prices rise to a level where they can flip the switch back on, production can resume as quickly as possible.

“A lot of times when you shut in wells, especially for a long period of time, you have a lot of surprises when you turn them back on. Some of them are good, some of them are bad,” Bretches told analysts in a conference call last month. “What can happen is you can end up with a lot of corrosion if you have not done everything in your power to make sure that you preserve those wells when you shut them in. So we’re taking great pains to make sure that preservation is going correctly.”

Continental Resources has cut production by 70 percent, shutting in almost all of its wells in North Dakota and cutting nearly 150,000 barrels of oil per day in May and June. CEO John Hart, however, said the Oklahoma-based company has more than a decade of experience drilling in the Bakken shale of North Dakota and doesn’t fear any damage from shut-ins.

“Our experience and our history in the plays we’re in shows us there’s no impact of shutting in production,” Hart told analysts last month. “So we don’t expect to have any impact whatsoever.”

https://www.houstonchronicle.com/business/energy/article/Turning-off-shale-wells-raises-questions-about-15320737.php&ct=ga&cd=CAIyGjQ3MzczNDYwZjA3ODRhOGI6Y29tOmVuOkdC&usg=AFQjCNHfKAANcfuVdFWWyhkDjVwIPTJOe

MANILA, Philippines — Over eight billion liters of fuel were already marked by the government to date after oil firms paid their correct import duties and excise taxes.

Bureau of Customs (BOC) Deputy Commissioner Teddy Sandy S. Raval told the Inquirer last Friday that as of June 4, 8.08 billion liters of oil products had been injected with chemical markers since the fuel marking program began last September.

Finance Secretary Carlos G. Dominguez III earlier said 20 companies regularly participated in fuel marking: Chevron, Era1, Filoil, Goldenshare, High Glory Subic, Insular Oil, Jadelink, Jetti, Marubeni, Micro Dragon, Petron, Phoenix, PTT, Seaoil, Shell, SL Gas, SL Harbor, Total/Filoil, Unioil, and Warbucks.

As of end-May, the biggest volumes of fuel were marked in Petron, Shell, Unioil, Chevron and Seaoil’s facilities.

The BOC and the Bureau of Internal Revenue (BIR) continued fuel marking even during the COVID-19 lockdown as the program had been exempted from the quarantine restrictions on movement of goods and people.

The BOC marked oil in depots, tank trucks, vessels, warehouses, and fuel-transporting vehicles.

For its part, the BIR tested in refineries and their attached depots, gasoline stations, and retail outlets.

The country’s two biggest revenue agencies have deputization and police authority during field testing so they can not only seize adulterated, diluted or unmarked petroleum but also arrest unscrupulous traders.

The joint venture of SGS Philippines Inc. and Switzerland-based SICPA SA had been producing and providing the ready-to-use official marker as well as conducting actual marking in all taxable oil products nationwide.

Fuel marking costs P0.06884 per liter, shouldered by the government during its first year of implementation.

The Department of Finance (DOF) targets to collect an additional P20 billion in tax revenues through fuel marking this year.

Last year, DOF officials estimated the total volume of fuel needed to be marked at 15.2 billion liters.

The fuel marking program was aimed at combating oil smuggling and misdeclaration to further raise government revenues.

In 2016, foregone revenues from excise taxes and value-added tax (VAT) uncollected from smuggled and misdeclared oil products amounted to P26.9 billion, over half of the actual P52.6-billion collections of the BOC and the BIR that year.

The Manila-based multilateral lender Asian Development Bank (ADB) had a larger estimate of P37.5-billion foregone tax revenues yearly no thanks to oil smuggling, while a study commissioned by domestic industry players had pegged revenue losses to as high as P43.8 billion annually.

https://business.inquirer.net/299402/tax-paid-marked-fuel-tops-8-billion-liter-mark&ct=ga&cd=CAIyGjYyMmNhMDFmYmUxYmFlODk6Y29tOmVuOkdC&usg=AFQjCNHiOrg7O_ifXdrZ1BC_4xIqvgx9a

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

As stay-at-home orders and mitigation efforts for the 2019 novel coronavirus disease (COVID-19) took effect and limited travel starting in the second half of March 2020, gasoline and jet fuel demand (as measured by product supplied) fell by near-record amounts, according to data in the U.S. Energy Information Administration’s Petroleum Supply Monthly.

From February to March, gasoline demand fell by 1.2 million barrels per day (b/d) (13%) to 7.8 million b/d, the lowest level since January 2000 and the second-largest monthly decline on record. During the same period, jet fuel demand fell by 242,000 b/d (15%), the largest single monthly change in U.S. jet fuel demand in EIA’s data, which dates back to 1965.

By comparison, demand for distillate fuel in March remained near its January and February levels, falling only 98,000 b/d (2%). Because of its stronger ties to economic activity, distillate consumption was initially less affected by COVID-19 mitigation efforts than gasoline and jet fuel, which are more closely tied to commuting and personal travel.

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

The drop in demand for petroleum products led refineries to limit operations: U.S. gross inputs into refineries fell by 670,000 b/d (4%) from February to March to average 15.8 million b/d, the lowest monthly level since October 2015.

The U.S. Gulf Coast region, or Petroleum Administration for Defense District (PADD) 3, is home to more than half of U.S. refining capacity. Unlike refinery runs in other regions of the United States, Gulf Coast refinery runs remained relatively unchanged between February and March as some refineries in the region returned to operation after maintenance in February. Also, Gulf Coast refineries tend to provide petroleum products to be exported or shipped to other parts of the United States, meaning their operations are less connected to in-region changes in demand.

Refineries in the other parts of the country decreased operations in March. In particular, gross inputs into refineries on the West Coast fell by 267,000 b/d (10%) from February to March.

Rapid changes in petroleum product demand and relatively slower changes in crude oil production and refinery operations led to increases in petroleum inventories. From February to March, U.S. crude oil inventories increased by 28.2 million barrels (6%) to reach 482 million barrels, the third-largest month-over-month increase in EIA data, which dates back to 1981, the beginning of the modern Petroleum Supply Reporting System.

As a result of these increases in inventory levels, in early April, EIA began to track oil storage utilization in the Weekly U.S. and regional crude oil stocks and working storage capacity report. This weekly tracker indicated that U.S. crude oil stocks reached 52% of working capacity the last week of March.

The data series presented in EIA’s Petroleum Supply Monthly are considered EIA’s definitive estimates of petroleum supply, disposition, and inventories. Other EIA products such as the Weekly Petroleum Status Report and the Short-Term Energy Outlook also provide near-term estimates and forecasts, respectively, of petroleum market metrics. A previous Today in Energy article discusses the differences in these products.

https://go.usa.gov/xw94h

New York (CNN Business) The oil market has rapidly recovered from its darkest day ever.

US crude topped $40 a barrel this week. That wouldn't typically be notable -- but right now, that marks an $80 leap from its unprecedented trip below zero just seven weeks ago, when it hit a low of -$40.32 a barrel on April 20. Meanwhile Brent crude, the world benchmark, has more than doubled since mid-April.

The remarkable oil recovery is being driven by hopes of a sharp rebound in the world economy from the coronavirus pandemic that crushed demand for gasoline, jet fuel and diesel.

The oil comeback also reflects enthusiasm for record-setting production cuts by OPEC, Russia and their allies, plus the sharp pullback in output from the United States, the world's leading producer.

Yet there are rising concerns that the rally in the oil patch is too good to be true. The glut of unneeded barrels hasn't gone away. Even the biggest oil bulls don't see demand returning to pre-pandemic levels anytime soon. And the threat of a second wave of coronavirus infections looms large.

"The market may have gotten a little ahead of itself. The risks are skewed sharply to the downside," said Bob McNally, president of consulting firm Rapidan Energy Group.

Oil traders are betting the vast oversupply of barrels that turned prices negative on April 20 will quickly vanish. But analysts stressed that this delicate rebalancing takes considerable time -- and it's no slam dunk.

Goldman Sachs: Fundamentals are 'turning bearish'

JBC Energy Group cautioned that oil prices will need a "confluence of bullish surprises" just to maintain current levels.

Goldman Sachs warned Monday that oil market fundamentals are "turning bearish" and prices will likely suffer a "pullback" in the coming weeks.

The Wall Street bank cited four major challenges: Demand expectations are "running ahead" of fundamentals; the level of inventories remains "daunting"; US shale and Libyan oil production is already restarting; and prices are approaching levels that will cause OPEC supply cuts to ease and Chinese purchases to slow.

Goldman Sachs expects US oil prices will average just $34 in the third quarter.

That's despite the latest efforts by OPEC to revive the market from its historic collapse. Last weekend, OPEC and all but one of its allied countries reached a deal to extend the record oil production cuts through July. Moreover, the group achieved new commitments to adhere to quotas from countries like Iraq and Nigeria that weren't doing so.

The agreement underscores dramatically improved relations within OPEC+ following the epic price war between Saudi Arabia and Russia.

"Russia and Saudi Arabia are no longer at each other's throats. They are arm-in-arm," said McNally.

Demand is returning

At the same time, the world's thirst for oil is slowly improving. The lifting of stay-at-home orders is naturally causing an uptick in demand for motor gasoline, jet fuel and diesel off extremely weak levels. Even New York City, the epicenter of the pandemic, is beginning to reopen its economy.

"End-user demand is clearly on the upswing," Michael Tran, director of global energy strategy at RBC Capital Markets, wrote in a Tuesday note to clients.

That's clear in US gasoline demand, which climbed by 885,000 barrels per day over the past week, according to RBC estimates based on real-time traffic data. That marks the best seven-day performance since stay-at-home orders were relaxed.

Although most models on Wall Street predicted supply-demand balances would flip into deficit later this month or early next, Tran said there are signs suggesting that bullish transition could happen weeks earlier than anticipated.

The pandemic isn't over

Of course, the risk is that the rebalancing in the oil market is derailed by a resurgence of coronavirus infections that causes authorities to abandon their reopening plans.

That's what is happening in Israel, which announced Monday it would "hit the emergency brake" on its reopening plans because of a sharp increase of coronavirus cases.

Morgan Stanley biotech analyst Matthew Harrison said in a note on Tuesday that the bank is monitoring for a potential "breakout" in states where new cases and/or hospitalizations are "accelerating again." Harrison listed Arizona, California, Oregon, Florida, South Carolina and Texas as states to watch. Morgan Stanley now predicts a total of 2.5 million Americans will get infected, up sharply from its forecast for 1.4 million infections just a month ago.

"A second wave of the pandemic isn't such a distant possibility anymore," Bjornar Tonhaugen, head of oil markets at Rystad Energy, wrote in a note on Tuesday. "If it is realized, oil demand, which has slowly been recovering, might plunge back to lockdown levels."

'Shale will come back.' But how fast?

Even if the health crisis remains under control, there is a risk that the rebound in the oil market will once again be self-defeating. In recent years, higher prices have encouraged oil companies, especially US frackers, to sharply ramp up output. That in turn led to excess supply.

ConocoPhillips COP "We do have to be worried about a double bump in this process,"CEO Ryan Lance said during a CERAWeek conversation that was published Tuesday.

Wall Street will strongly urge once-booming shale companies to exercise restraint as they dip their toes back in the water.

"Shale is not broke; shale is not gone; shale will come back," Lance said. "But I do think it comes back slower because there's going to be pressure on companies to refine their capital program, maybe not grow dramatically as they were before."

McNally, the Rapidan Energy president, agreed that shale oil companies will be careful.

"After an $80 swing in oil prices, the champagne is not yet uncorked," he said. "It's way too early to celebrate."

https://www.cnn.com/2020/06/09/investing/oil-prices-opec-coronavirus/index.html&ct=ga&cd=CAIyHGUzNTNmYzI0N2YyZGM3ODQ6Y28udWs6ZW46R0I&usg=AFQjCNHswyUUJfUa_3m6dmH7_iR5ngwgm

Armed individuals entered Libya’s largest oil field, El Sharara, just a day after reports said the field had restarted production after months of idling amid the ongoing civil war. Another force majeure has been declared.

Reuters quotes the National Oil Corporation as saying the “armed force” had told the workers on the field to stop working just hours after they had begun planned maintenance at the field. NOC itself told its employees not to obey that order. Details about the armed force were not disclosed.

"The armed group, which came from Sebha, stormed the Sharara oilfield and pulled their guns on civilian unarmed workers, coercing them to stop production at the field at dawn," the NOC said in a Tuesday statement.

The first production phase at Sharara was supposed to begin at a capacity of 30,000 bpd, Libya’s state oil firm said in a statement, noting that production was expected to return to full capacity within 90 days due to the damages caused by the long shutdown. The field has a total production capacity of 300,000 bpd.

Libya also restarted a second oilfield over the weekend, the 70,000-bpd El Feel which is linked to Sharara, a field engineer told Reuters on Sunday.

Libya’s oil industry ground to halt after the Libyan National Army, a group affiliated with the eastern government of Libya, blockades the oil export terminals of the country. The blockade was part of the LNA’s offensive against Tripoli and the UN-supported government.

Fighting has been ongoing since then, with oil production falling from over 1 million bpd to less than 100,000 bpd, with exports shrinking by 92 percent between January and May. The NOC also said last month the total losses incurred from the blockade and the production outages had reached $5 billion.

“The first quarter of 2020 was a huge decrease in revenues for Libya, as a direct result of the illegal blockade of numerous oil and gas facilities. This is only part of the picture, as the corrosion in pipes caused by still oil and salt water is resulting in physical damage that will cost millions to fix when the crisis is over,” NOC’s chairman, Mustafa Sanalla said in late May.

https://oilprice.com/Energy/Crude-Oil/Libyas-Largest-Oil-Field-Shuts-Down-Just-One-Day-After-It-Restarted.html&ct=ga&cd=CAIyHGUzNTNmYzI0N2YyZGM3ODQ6Y28udWs6ZW46R0I&usg=AFQjCNH8hN3uPS8L0sQulEOwU8dk9Z-aW

Saudi Arabia has instigated two oil price wars in the last decade and has lost both. Given its apparent inability to learn from its mistakes it may well instigate another one but it will lose that as well. In the process, it has created a political and economic strait-jacket for itself in which the only outcome is its eventual effective bankruptcy. OilPrice.com outlines why this is so below.

The principal target for Saudi Arabia in both of its recent oil price wars has been the U.S. shale industry. In the first oil price war from 2014 to 2016, the Saudi’s objective was to halt the development of the U.S. shale sector by pushing oil prices so low through overproduction that so many of its companies went bankrupt that the sector no longer posed a threat to the then-Saudi dominance of the global oil markets. In the second oil price war which only just ended, the main Saudi objective was exactly the same, with the added target of stopping U.S. shale producers from scooping up the oil supply contracts that were being unfilled by Saudi Arabia as the Kingdom complied with the oil production cuts mandated by various OPEC and OPEC+ output cut agreements.

In the run-up to the first oil price war, the Saudis can be forgiven for thinking that they stood a chance of destroying the then-relatively nascent U.S. shale sector. It was widely assumed that the breakeven price across the U.S. shale sector was US$70 per barrel and that this figure was largely inflexible. Saudi Arabia also held record high foreign assets reserves of US$737 billion at the time of launching the first oil war. This allowed it room for manoeuvre in sustaining its economically crucial SAR-US$-currency peg and in covering any budget deficits that would be caused by the oil price fall. At a private meeting in October 2014 in New York between Saudi officials and other senior figures in the global oil industry, the Saudis were ‘extremely confident’ of securing a victory ‘within a matter of months’, a New York-based banker with close knowledge of the meeting told OilPrice.com. This, the Saudis thought, would not only permanently disable the U.S, shale industry but would also impose some supply discipline on other OPEC members. Related: Will U.S. Shale Ever Return To Its Boom Days?

As it transpired, of course, the Saudis had disastrously misjudged the ability of the U.S. shale sector to reshape itself into a much meaner, leaner, and lower-cost flexible industry. Many of the better operations in the core areas of the Permian and Bakken, in particular, were able to breakeven at price points above US$30 per barrel and to make decent profits at points above US$37 per barrel area, driven in large part through advances in technology and operational agility. After two years of attrition, the Saudis caved in, having moved from a budget surplus to a then-record high deficit in late 2015 of US$98 billion. It had also spent at least US$250 billion of its precious foreign exchange reserves over that period that were lost forever. In an unprecedented move for a serving senior Saudi politician, the country’s deputy economic minister, Mohamed Al Tuwaijri, stated unequivocally in 2016 that: “If we [Saudi Arabia] don’t take any reform measures, …then we’re doomed to bankruptcy in three to four years.”

The even more enduring legacy of this first oil price war, though – and part of the reason why the Saudis could never hope to win the last one, or any future oil price war either – is that it created the resilience of the U.S. shale sector as it now stands. This means that the U.S. shale sector as a whole can cope with extremely low oil prices for a lot longer than it takes Saudi Arabia to be bankrupted by them. Saudi Arabia has much greater fixed costs attached to its oil sector, regardless of how low market prices go. Before the onset of the latest oil price war, the Kingdom had an official budget breakeven price of US$84 per barrel of Brent but, given the economic damage done by this latest price war folly, it is much higher now. By stark contrast, the U.S. shale sector that Saudi crucially helped to shape in the first oil price war is now so nimble that US$25-30 per barrel of WTI is enough to bring some of the production back on line, as long as operators believe that prices will not fall and hold below the US$20 per barrel level. But, even if prices are below that key US$25-30 per barrel level, it does not matter to the long-term survivability of the U.S. shale sector as the key players are able to shut down wells instantly as and when needed and to start up them up again within a week as demand requires. In sum: in any oil price war, the Saudis simply cannot wait out the U.S. shale sector.

On the other hand, though – in a rising oil price environment - the Saudis are also doomed. This is because the U.S. – even before the latest oil price war – had intimated that it would not tolerate oil prices above around US$70 per barrel of Brent. When the oil price rose last year during the March-October period consistently above US$70 per barrel level, U.S, President Donald Trump Tweeted about Saudi Arabia’s King Salman that: “He would not last in power for two weeks without the backing of the U.S. military.” The US$70 per barrel level is considered one that brings into view oil price levels that might pose problems for the U.S. economy. Specifically, it is estimated that every US$10 per barrel change in the price of crude oil results in a 25-30 cent change in the price of a gallon of gasoline, and for every 1 cent that the average price per gallon of gasoline rises, more than US$1 billion per year in consumer spending is lost. Related: OPEC+ Agrees On Extending Record Output Cuts

Before this latest Saudi-instigated oil price war, the U.S. had little interest in the fact that this US$70 per barrel level was way below Saudi Arabia’s then-budget breakeven oil price. After this latest attack on its strategically vital shale sector, the U.S. has absolutely no interest whatsoever in this budget breakeven fact or indeed in whether Saudi Arabia continues to slowly haemorrhage into bankruptcy in the coming years, according to a number of Washington-based sources close to the U.S. Presidential Administration spoken to by OilPrice.com in the last few weeks. Partly this indifference is due to the perceived ‘betrayal’ of the foundation stone deal that had determined the two countries relationship since 1945. This was that the U.S. would receive all of the oil supplies it needed for as long as Saudi Arabia had oil in place, in return for which the U.S. would guarantee the security of the ruling House of Saud. This altered slightly with the advent of the U.S. shale sector to ensure that Saudi Arabia also allows the U.S. shale industry to continue to function and grow.

Partly as well, this indifference is due to the series of other blunders that senior U.S. politicians believe have been made by Saudi Crown Prince Mohammed bin Salman (MbS), which now make him a liability. This includes – but is not limited to – the Saudi-led war in Yemen, the cosying up of Saudi to Russia in the OPEC+ grouping, Lebanese President Michel Aoun’s allegation in 2017 that then-Prime Minister Saad al Hariri had been kidnapped by the Saudis and forced to resign, and the murder of dissident Saudi journalist, Jamal Khashoggi, which even the CIA concluded was personally ordered by MbS.

These factors culminated in President Trump making his earlier Tweeted implied threat about the fragile hold that the al-Sauds have on power in Saudi Arabia without U.S. assistance into a guaranteed promise during a telephone conversation on 2 April with MbS. During this call, Trump reportedly told MbS that unless OPEC started cutting oil production (with the implication being to push up prices to levels where the U.S. shale producers could start making decent profits) then he would be powerless to stop lawmakers from passing legislation to withdraw U.S. troops from Saudi Arabia. Shortly thereafter, MbS did what he was told. The change in this rhetoric from implied threat to guaranteed action means that this is now in the fabric of all future U.S. dealings with Saudi Arabia and it brings the Saudis crashing back to the basic problem. That is: economically it cannot afford to continue to crush oil prices for long enough to cause sustained damage to the U.S. shale sector, politically it is not permitted to allow prices to rise high enough to avoid eventual effective bankruptcy, and any pricing in between just allows the U.S. shale sector to make greater profits and grow even more. In this regard, the OPEC+ production cuts are perhaps the cruellest cut of all for the Saudis: the Saudis have to implement them and abide by them because they are needed to keep oil prices high enough to ensure the profitability and growth of the U.S. shale sector but the cuts cannot continue for long enough to allow the Saudis back into an ongoing budget surplus.

Already in this context, March saw Saudi Arabia’s central bank depleted its net foreign assets at the fastest rate since at least 2000, falling by just over SAR100 billion (US$27 billion). This is a full 5 per cent decrease from just the previous month, and the total reserves figure now stands at just US$464 billion, the lowest level since 2011. It leaves only US$164 billion of ‘fighting reserves’ that can be used on everything else that Saudi needs when the US$300 billion that is estimated to be needed to keep the economic cornerstone SAR/US$-peg is subtracted. At the same time, the Kingdom slipped into a US$9 billion+ budget deficit in the first quarter and a number of independent analysts are predicting that its overall gross domestic product could shrink by more than 3 per cent this year (the first outright contraction since 2017 and the biggest since 1999), whilst the budget deficit could widen to 15 per cent of economic output.

https://oilprice.com/Energy/Energy-General/Why-Saudi-Arabia-Will-Lose-The-Next-Oil-Price-War.html&ct=ga&cd=CAIyGjQ3MzczNDYwZjA3ODRhOGI6Y29tOmVuOkdC&usg=AFQjCNFYcD0dBl0dRFse1r539-k5SjDNP

The year started as 2019 had ended for leading natural gas marketers, with 1Q2020 continuing the sales declines that have hampered the industry for four consecutive quarters, according to NGI’s Top North American Natural Gas Marketers rankings.

The 23 gas marketers that participated in both NGI's latest quarterly survey and the year-ago survey reported combined sales transactions of 122.85 Bcf/d in 1Q2020, a 4% decline compared with 127.63 Bcf/d in 1Q2019. The addition of two marketers since the 1Q2019 survey -- Hartree Partners (2.05 Bcf/d) and Engie Energy Marketing NA (1.04 Bcf/d) -- brought the 1Q2020 survey total to 125.94 Bcf/d.

It was the fourth consecutive quarterly NGI survey to report year/year declines. Prior to decreases reported in the 2Q2019 survey, marketers had reported year/year increases in six consecutive surveys. The NGI survey ranks marketers on sales transactions only. The Federal Energy Regulatory Commission Form 552 tallies both purchases and sales.

In the latest survey, seven of the survey's Top 10 marketers, including the three leaders, as well as 16 companies overall, reported lower numbers in 1Q2020 than in the year-ago period. Substantial year/year declines were reported by BP plc (19.83 Bcf/d, compared with 22.22 Bcf/d in 1Q2019) and Macquarie Energy (11.69 Bcf/d from 13.04 Bcf/d in 1Q2019), the survey’s perennial No. 1 and No. 2, respectively.

London-based BP, for years the top gas marketer in North America, in February set ambitious targets to become a net zero carbon emitter by at least 2050. Last year, BP’s shareholders voted overwhelmingly to approve a resolution aligning the business strategy with the 2015 United Nations climate change accord, aka the Paris Agreement.

Year/year declines were less dramatic for Tenaska (10.70 Bcf/d, a 3% decline compared with 11.00 Bcf/d in 1Q2019) and Shell Energy NA (9.90 Bcf/d) was unchanged compared with the year-ago period. ConocoPhillips (8.49 Bcf/d) reported only a 1% decline.

Direct Energy (7.50 Bcf/d) bucked the downward trend, reporting a 6% increase compared with 1Q2019, enough to bump it up one spot to No. 6 in the NGI survey.

Rounding out the Top 10 were Sequent Energy Management (6.90 Bcf/d, a 1% decrease), J. Aron & Co. (5.60 Bcf/d, an 18% decrease), EDF Trading NA (4.44 Bcf/d, a 7% decrease), and Chevron Corp. (4.36 Bcf/d, a 2% increase).

With Covid-19 mitigation efforts only recently beginning to be relaxed and the Atlantic hurricane season off to a roaring start, 2Q2020 might not provide marketers with any better opportunities than 1Q2020.

“Drilling and production have been pulling off at a historic pace and this could continue into the second quarter, although the recent recovery in oil prices to near $40/bbl could moderate this trend as some oil wells become economic in low cost areas such as the Permian Basin,” said NGI market analyst Nate Harrison.

“While the ‘curve’ of new daily cases of Covid-19 continues to flatten/decline, there has been a recent uptick over the past week, likely due to the protests sweeping the nation. While some speculate the close-quarters gatherings of protesters could spark a new wave of cases, it's unclear whether a second wave of the virus could lead to lockdown measures being reimposed later this year.

“Volatility in the benchmark Henry Hub futures price has been in decline since the middle of May, with the Bollinger bands contracting the most over the past week. Contracting Bollinger bands, especially when accompanied by lower trading volumes, are often a leading indicator of a technical breakout.”

U.S. dry gas production averaged 92.2 Bcf/d in 1Q2020, but in 2Q2020 output has stumbled to 87.7 Bcf/d through Monday (June 8).

“Domestic dry gas production has rebounded a bit since bottoming at 82.7 Bcf/d, and has been anywhere between 83.8 Bcf/d and 84.5 Bcf/d thus far in June,” said NGI’s Patrick Rau, director of Strategy and Research. “Meanwhile, industrial and liquefied natural gas demand continue to trend lower, although power generation demand has stepped up to help fill the void. As such, there could very well be a bit of a shakeup in the 2Q2020 rankings versus the first quarter of the year.”

The equation for marketers could be further complicated by what forecasters say could be more active than normal Atlantic hurricane season. Though storms don’t pack the same punch they once did on gas supplies, they now can have a more pronounced impact on the demand side. Already the 2020 hurricane season, which officially began June 1, has produced Tropical Storm Arthur, Tropical Storm Bertha, and Tropical Storm Cristobal, which forced some shut-ins as it crossed the Gulf of Mexico and came ashore in Southeast Louisiana Sunday.

Other highlights of NGI’s 1Q2020 survey included a 57% increase year/year for ARM Energy Management (3.16 Bcf/d), a 6% increase for ExxonMobil (3.14 Bcf/d), a 4% increase for Cabot Oil & Gas Corp. (2.36 Bcf/d), and an 11% increase for Ovintiv (1.57 Bcf/d), formerly Encana Corp.

https://www.naturalgasintel.com/articles/122239-another-rough-road-in-1q2020-for-top-us-natural-gas-marketers&ct=ga&cd=CAIyHGE0NjNlMGVlODc0Mjk3NmU6Y28udWs6ZW46R0I&usg=AFQjCNGP2h1TnzsJDHQaCE69pIviIB1VX

- The Financial Times reported that oil trading giant Vitol saw profits plunge in the first quarter of 2020, dropping from around $600 million in Q1 last year, to just $180 million now, a fall of 70%.

- The firm, the world's largest oil trader, was hit hard by the crash in oil prices, and by a bet by one trader that turned sour, the FT reported.

- US oil prices turned negative in mid-April due to tanking demand during the pandemic and lack of storage space.

- Vitol is said to have "done well" in the week prices turned negative, the FT added.

The oil market crash in late April blindsied many in the markets, and hardly anyone was spared - not even the world's largest oil trader.

The Financial Times reported Tuesday, citing multiple confidential sources, that Vitol's net income fell 70% in the first quarter to $180 million. During the same period last year the company made around $600 million, the FT said.

As the FT reports, Vitol's significant loss of income during the crash likely came as a surprise to CEO Russell Hardy, who in February said on Bloomberg TV that: "The expectation of the market today is it's not going to get significantly worse than what we've seen."

Hardy's comments came before Saudi Arabia and Russia kicked off a price war in March, and demand for the commodity took a massive beating during the pandemic with every major economy placed under lockdown.

The US oil market also faced negative prices in April after the May futures contract expired, forcing traders to face taking physical delivery of their oil, or sell it at a loss.

Part of Vitol's struggle, the FT reported, was caused by a bet by one partner - Yaoyao Liu - who the newspaper said built a large position betting on an oil recovery after it's initial crash in late February and early March.

The newspaper, which referred to Liu as a "whizz kid," said he cited China's speedy move out of lockdown as showing that government's could handle the virus quickly, and that oil demand would recover. However, the FT added, the "bet turned sour."

Brent crude, the international benchmark more than halved, falling from almost $60 a barrel to $25 in March.

It is unclear how much Liu's bet lost, but the FT also reported that a recruiter had emailed a rival oil trading house to say that Vitol had lost as much as $1.6 billion.

The company denied that number and demanded a retraction from the recruiter in question, which it received, the FT added.

While Vitol lost money on Liu's bet, the FT said, it managed to perform strongly during the week in which oil prices dropped below zero for the first time ever, buying up cheap oil for storage and sale once prices recovered.

"Vitol is said by three rivals to have done well," during that week, the FT said.

Vitol did not immediately respond to a request for comment on the Financial Times' story when contacted by Business Insider.

Oil prices have recovered since WTI turned negative in April, partly due to the easing of lockdowns and OPEC production cuts. The international coalition announced it would slash production by 9.7 million barrels over May and June. On Saturday, the OPEC+ extended the production cuts until July.

Both oil benchmarks are trading lower Tuesday, with Brent hovering just above $40.45 per barrel, down 0.9%, and WTI down 0.5% at $37.20 as of 8.30 a.m. ET.

https://www.businessinsider.com/oil-price-vitol-worlds-biggest-trader-profits-drop-70-percent-2020-6&ct=ga&cd=CAIyGjk5YzNmM2Y0NmU2Yjk4MTk6Y29tOmVuOkdC&usg=AFQjCNHg_LNyxd_sx7MRmblTl5CMHC4E1

Recent international oil price hikes are unlikely to gain further momentum in the near future due mostly to internal conflict among oil producers over production cuts and COVID-19 showing signs of sporadically flaring up, industry watchers said Monday.

Experts and financial institutions view crude oil prices rising to pre-pandemic level as unlikely for the time being given virus-triggered demand shock will not see an immediate recovery with the travel and airline industries reeling from a rapid deterioration of profits.

Brent Crude prices topped $40 (48,100) a barrel early June 3 (local time), the first time since two global oil powers ― Saudi Arabia and Russia ― began a war defined by production cuts following the breaking of a pact signed by Organization of the Petroleum Exporting Countries (OPEC) Plus, the group of primary oil producers, March 6.

The prices have since fluctuated, with Brent Crude hovering around $43 and Western Texas Intermediate (WTI) $40 as of Monday.

The sharp recovery is notable given the WTI fell into the negative territory in April, an unprecedented drop led by a massive supply overhang brought on by the pandemic.

"The price bounced back faster than we expected," Korea Energy Economics Institute (KEEI) oil policy research team head Jung Jun-hwan said.

The state-run institute had forecast that the price would not jump to the current level before the third quarter of 2020, an assessment made before a decision on a production cut of 9.7 million barrels a day reached over the weekend.

The producers, reflecting a shared concern over possible price drops, reached an agreement, Saturday (local time) to a production cut of 9.7 million barrels a day through July.

This is a change from an earlier stance reiterated April 12 when OPEC Plus agreed to increase production in steps after June.

Despite the cut, the price will not recover to around $63, a level maintained before the pandemic, given recovery in oil demand will not come as hardest-hit industries will not be able to snap out of their deep economic slumps any time soon, he added.

"The price will not rise dramatically before the third quarter when demand recovery should begin to materialize. Our view is that the oil price will average at $40 in the first half as well as the latter half," Jung said.

http://www.koreatimes.co.kr/www/biz/2020/06/175_290888.html&ct=ga&cd=CAIyGjk5YzNmM2Y0NmU2Yjk4MTk6Y29tOmVuOkdC&usg=AFQjCNF1p0Jy__YQZrqnoVtlk_f8ho6NM

By the end of the second quarter of 2020, data from drill bits may tell us whether or not the world has found the next Eagle Ford, and it’s all going down in Africa ...

To hear mainstream media tell it, you would think that the oil and gas era is coming to an end. That assertion, however, could not be further from the truth. The world’s thirst for oil is set to keep soaring with oil demand growth not likely to peak over the next two decades as economies in the developing countries continue to expand.

Over the past five years, we have seen far less exploration and discovery of oil than what we are consuming. In other words, the world still needs new oil. Existing fields are declining at 3-4% per year.

The new oil that’s coming online offshore Guyana, Brazil and Norway this year will help to close that gap somewhat, but the continued decline in U.S. shale fields could upset the equation.

That calls for the African continent to step up to the plate, and also brings to the world’s attention a country that has never before produced oil: Namibia, a new frontier and home to a basin that rivals Eagle Ford in size and hopes to rival it in potential.

This is the Kavango Basin, a 6.3-million-acre basin with a 12-billion-barrel original oil in place potential, and the entire basin was recently acquired by an ambitious Canadian explorer called Reconnaissance Energy Africa Ltd (TSXV: RECO, OTC: RECAF)

Africa: Vastly Underexplored

New producing countries from sub-Saharan Africa are beginning to redraw the continent’s oil and gas map. Today, the putative class valedictorians, Nigeria and Angola, together pump around 4 million barrels per day (bpd) of crude and also dominate natural gas output. Only a handful of other countries in the region produce more than a couple of hundred thousand barrels of oil and gas equivalent.

A few years from now, however, the balance could be very different with Uganda, Kenya, Ghana and Niger developing fields each with a potential capacity for over 100,000 bpd of oil.

Now, Reconnaissance Energy Africa is hoping to put Namibia on the map onshore, while supermajors such as Exxon, Shell and Total SA are hoping to bring Namibia fame offshore.

A few years ago, during the shale boom, Recon Africa went looking for shale in Namibia and discovered a deep giant basin, the Kavango Basin.

The Kavango Basin is an extension of the Permian Karoo shales of South Africa, Botswana and Namibia. It’s never seen a drill bit, yet it could become an analogue to one of the world’s largest shale discoveries in South Africa. The ultra-deep basin simulates in many ways the kind of environment you see in Eagle Ford:

- 6.3 million total acres to Eagle Ford’s 6.7 million acres in geographic size

- Potential for an estimated 12 billion barrels OOIP (Original Oil in Place) and 119 TCF OGIP(Original Gas in Place), to be determined whether it’s actually there and if so, technically recoverable. If it were, that’s significantly higher than Eagle Ford’s 2.4 billion OOIP and 50 TCF OGIP.

Speaking to Oilprice.com, Jay Park, CEO of Recon, said he and his team immediately recognized the vast potential of the basin and obtained licenses from the Namibian government.

The company now holds the entire Kavango Basin in Namibia under Petroleum Exploration License 73. ReconAfrica owns 90% interest in Petroleum Exploration License 73, while Namibia's state-owned oil company, National Petroleum Corporation of Namibia holds the remaining 10%.

Drilling to Start in June

Earlier this month, Recon Africa entered into a binding Asset Purchase Agreement with Houston-based Henderson for the acquisition of a Crown 750 drilling rig for $1.8 million, and the Kavango Basin will have its first drill bit hit the ground in June this year.

Recon has a 4-year exploration license leading to a 25-year production license starting when it has made a commercial discovery.

Sproule - a tier 1 resource assessment company - estimated that Kavango has a potential 12 billion barrels of oil or 119 trillion cubic feet of natural gas. That’s for the shale and doesn’t count any conventional potential.

Why Namibia?

There are several very important reasons why ReconAfrica has zoomed in on Namibia.

Many otherwise high-potential states in Africa have struggled with their petroleum regimes. These countries tend to create regimes that are too complex and heavily taxed. They also fail to give investors the assurances they need.

“Investors want to be confident that when they make a discovery, it will turn into money,” says Park. “While Africa is the place to go for resources, many of its regimes don’t meet the desired investment objectives, for example through inadequate environmental policies.”

ReconAfrica filtered through various countries and Namibia came out very high for all of these targets--a balance of great resource potential, investor-friendly fiscal terms and a good, stable and legal regime.

“A geologist might point out that Saudi Arabia has the best rock formations on earth, but you can’t get a license grant from the state there. Libya is likely to have a great shale resource, but taxation experts would point out that the state taxes oil and gas at over 90%, so shale would become an impossible proposition,” Park notes.

The Kavango Basin has similar geology, and it’s also been shown to have the same depositional environment as Shell’s Whitehill Permian shale play, part of the Karoo Supergroup in South Africa.

If the giant Karoo Basin in South Africa is a shale windfall, the Kavango Basin in Namibia is its likely extension, according to geologists.

And while it’s pretty unheard of for a company this small to have a basin this big, Bill Cathey, go-to geophysicist for the supermajors, has weighed in as well.

When Recon brought the magnetic survey data from Namibia’s Kavango Basin to Cathey, Cathey said the data showed a 30,000-foot sedimentary basin. He also said that a basin this deep, everywhere else in the world, produces commercial hydrocarbons. That’s when Recon’s senior management dropped everything to scoop up the basin, says Park.

But Recon Africa isn’t the only party interested in Africa’s potential as a new frontier.

Exxon (NYSE:XOM) recently acquired additional 7 million net acres from the Namibian government for a block extending from the shoreline to about 135 miles offshore in water depths up to 13,000 feet, with exploration activities to begin by the end of this year.

What Exxon’s banking on is that Namibia, which once fit together with Brazil, shares the same geology as Brazil’s pre-salt bonanza basins, Santos and Campos, which have already proved enormously resource-rich, according to Deloitte.

Likewise, French oil giant Total SA (NYSE:TOT) is ready to launch a three-well drilling campaign that includes one of the deepest wells ever drilled in Africa--two wells in Angola and one in Namibia. Even Qatar Petroleum is farming into Total’s Namibia blocks, while Shell (NYSE:RDS.S) is delineating a deep-water wildcat prospect offshore Namibia that it will spud this year. Shell is a veteran in the African oil and gas game. The company began drilling in the region in the 1950s, and now has assets in over 20 countries across the continent. Though it has sold off a number of assets in the region in recent years due to unfavorable regimes, it continues to maintain a strong presence in South Africa and Namibia.

Though there are a number of exciting hotspots popping up across Africa, it’s also important to pay attention to oil companies taking big risks on little-known exploratory projects.

Take Total, for example. It recently announced a major oil discovery offshore Suriname with its partner, Apache (NYSE:APA). Apache’s agreement with Total included $100 million upfront payment and expenses incurred in exploration. The find was a major boon for both Total and Apache, especially considering there had not previously made any commercially viable oil discoveries. The find is doubly beneficial for Suriname, which could be a significant turning point for the small country’s economy.

Though it’s not entirely off the beaten path, Egypt has also captured the attention of Big Oil in recent years. Just last month, in fact, the country awarded Chevron (NYSE:CVX) and Shell key exploration blocks in the red-hot Red Sea. The blocks cover a total area of around 10,000 sq km and carry combined minimum investment of $326 million, Egypt’s petroleum ministry said, adding that potential investment would rise to "several billion dollars" if discoveries were made.

Other companies to watch as the exploration and production industry ramps up:

Husky Energy Inc (TSX:HSE): This integrated oil and gas company out of Western Canada lives up to its name, fierce and driven for success. It’s already got a presence in some of the most well-known oil regions on the planet, but it hasn’t stopped there. It’s even positioned itself in Europe, Africa and as remote as the South China Sea.

Suncor Energy (TSX:SU): As one of the biggest names in energy, Suncor has adopted a number of high tech solutions for finding, pumping, storing, and delivering its resources.

While its primarily based out of North America, its assets in Africa and the Middle East should not be ignored. Though the oil downturn has weighed on the company’s share price this year, many analysts are pointing to a turnaround, from which Suncor is likely to benefit.

Tourmaline Oil Corp (TSX:TOU) is another Canadian resource producer focusing on exploration, production, development and acquisition within Western Canadian Sedimentary Basin. The company is in possession of an extensive undeveloped land position with long-term growth opportunities and a large multi-year drilling inventory.

Tourmaline’s strong leadership make the company a promising pick for investors looking to take advantage of the tremendous Canadian oil opportunities which are due for a strong rebound as oil prices inch higher.

Imperial Oil (TSX:IMO) still has some of the lowest cost producing oil sands in Canada and that is going to pay off as oil prices continue to rise and new tech breakthroughs bring breakeven prices even lower.

The management is well known for being conservative, but that certainly shouldn’t put investors off in a time when recovery is the buzzword of the day and consistency is sure to be rewarded.

Gibson Energy (TSX:GEI): has a long history in Canada’s oil and gas game. Established in 1953, Gibson knows the industry inside and out. The company has a diverse portfolio which includes transportation, storage, processing, marketing and distribution of oil, condensates, oilfield waste, refined products and natural gas.

With Gibson’s huge array of assets and its multi-platform sales strategies, investors look to Gibson with confidence.

https://finance.yahoo.com/news/world-next-oil-hotspot-230000952.html

London — OPEC and its allies slashed almost one-fifth of their crude oil production in May, the first month of their landmark supply accord, according to the latest S&P Global Platts survey of the group's output.

Prodded by the coronavirus pandemic and oil market meltdown to implement an unprecedented 9.7 million b/d in collective cuts, the 23-country OPEC+ coalition mostly delivered.

OPEC's 13 members dropped their output to 24.32 million b/d, for a compliance rate of 82% with their prescribed cuts, the survey found. Russia and nine other partners performed better, pumping a combined 13.89 million b/d and making 91% of their cuts, bringing the whole OPEC+ group's collective compliance to 85%, according to Platts calculations.

The supply curbs are scheduled to run through July, the OPEC+ alliance announced at its June 6 meeting, as the bloc seeks to speed the market's recovery from the pandemic.

The compliance figures are being closely monitored by OPEC+ members, who agreed that any shortfalls in May and June compliance would be made whole with extra production cuts this summer.

OPEC members Iraq, Nigeria and Angola, along with non-OPEC participant Kazakhstan have already been publicly called out by their counterparts for their overproduction.

Iraq, whose history of quota flouting has long been a sore spot among the coalition, pumped 4.19 million b/d in May, nearly 600,000 b/d above its cap, making it the worst offender by far, the Platts survey found.

Nigeria, also frequently out of compliance, produced nearly 300,000 b/d in excess of its quota, while Angola was 90,000 b/d above its target and Kazakhstan was 161,000 b/d over, according to the Platts figures.

Ministers from all four countries have declared their allegiance to the OPEC+ agreement and pledged to improve their performance going forward.

But they are not the only producers with work to do.

Russia, the main non-OPEC partner, pumped 8.60 million b/d, about 110,000 b/d more than its quota, according to the survey. Russian energy minister Alexander Novak had teamed up with Saudi counterpart Prince Abdulaziz in the weeks leading up to the June 6 meeting to pressure Iraq and other noncompliant members to commit to extra cuts.

Saudi Arabia produced 8.50 million b/d, the survey found, almost in line with its quota of 8.49 million b/d. That is the kingdom's lowest output since January 2011, not including September 2019, when a missile attack on its Abqaiq crude processing facility temporarily caused half of the country's capacity to be shut-in.

Determining quotas

The OPEC+ deal calls for cuts of 23% from baseline production levels in October 2018, except for Saudi Arabia and Russia, who were given identical baselines of 11 million b/d.

In all, the OPEC+ coalition lowered its output by a combined 8.28 million b/d from the baseline of 43.85 million b/d.

A nine-country monitoring committee co-chaired by Saudi Arabia and Russia will convene on June 18 and monthly thereafter to assess compliance and make recommendations on quotas going forward. The collective production cuts are scheduled to roll back to 7.7 million b/d in August, for now.

Sanctions-hit Iran and Venezuela are exempt from the quotas, as is war-torn Libya. Iran kept its output steady at 2.02 million b/d in May, while Venezuela's production fell to 550,000 b/d, the survey found.

Libya, with its ports blockaded by rebel militia, pumped just 70,000 b/d in May, but could see a rebound in the coming weeks pending the outcome of negotiations with tribes controlling its southern fields. But its security remains volatile.

http://plts.co/4dSZ50A3GAE

More oil and gas disruptions likely as civil war escalates

London — Libya's two key western oil fields -- El Feel and Sharara -- have been closed again shortly after reopening, showing the extent to which they remain hostage to armed groups as the country's civil conflict continues to escalate.

State-owned National Oil Corporation said the 75,000 b/d El Feel field had been shut June 10 after an armed group occupied the field.

NOC also said the 300,000 b/d Sharara field was shut late June 9 after the field opened twice briefly in the space of four days.

A key pipeline valve connecting the Sharara and El Feel fields with the Zawiya terminal and refinery had reopened June 5, paving the way for a resumption of output. Both sites were shut for almost five months due to a blockade that has dragged Libyan output to its lowest in 9-1/2 years.

NOC declared force majeure on crude loadings out of Sharara on June 9 after the group entered the area.

The recent stop and start events underscore the fragility of the country's much anticipated return to export markets.

The North African oil producer is in the midst of a civil conflict between the UN-backed Government of National Accord (GNA) and the self-styled Libyan National Army (LNA), which has almost completely decimated its oil output.

The GNA has recently gained ground against the LNA led by Khalifa Haftar, causing some tribal groups and militias to switch allegiances but the situation remains extremely fluid and volatile.

Gas impact

The gas market was also impacted this week when on June 10, an armed group stormed the Mellitah oil and gas complex, from where the country exports gas to Italy via the Greenstream pipeline.

Sources said operations at the complex were briefly halted and that the group had left the complex by the afternoon.

The group loyal to the GNA had entered the facility and were hoping to stop supplies to Italy after it signed a maritime agreement with Greece.

Turkey, is currently at loggerheads with regional neighbors such as Cyprus, Greece along with Israel and Egypt over gas drilling and gas projects in the East Mediterranean.

The LNA -- backed by Russia, the UAE, Saudi Arabia and other countries -- has been locked in a bitter conflict with the government supported primarily by Turkey and Qatar. Oil and now gas facilities have been caught in the middle of their dispute.

Much of the gas that feeds the Mellitah gas terminal -- the starting point of the Greenstream pipeline -- comes from Wafa and the Bahr Essalam field, Libya's biggest offshore gas field.

Supplies of natural gas from Libya via the Green Stream pipeline to Italy have been mostly unaffected by the blockade of key oil infrastructure by the LNA.

More disruptions likely

S&P Global Platts Analytics said recent events showed Libya's potential restart of up to 400,000 b/d from southwestern fields faced many risks, and sporadic disruptions were likely to persist.

"Eastern general Khalifa Haftar could regroup with greater backing from the UAE, Egypt, and Russia, while Libyan production dynamics over the past few years indicate regional militias will likely continue to at least sporadically disrupt the fields and connected pipelines," said Paul Sheldon, chief geopolitical adviser at Platts Analytics.

Hamish Kinnear, a MENA analyst at Verisk Maplecroft said the struggle and rapidly changing situation at the fields reflected the wider fluidity of the civil war.

Libya's potential return to export markets with up to 400,000 b/d of mainly Es Sider and Sharara grade crudes comes as its partners in OPEC and their allies agreed on extending production cuts to cuts through July, to help bolster the market as it emerges from the depths of the COVID-19 pandemic.

Libyan crude production was around 70,000-80,000 b/d, less than 10% of levels before January 18, when the LNA orchestrated an oil port blockade. Production was then at its lowest since September 2011, when civil war led to the downfall of Moammar Qadhafi.

Libya holds Africa's largest proven oil reserves. However, chronic political turmoil has undermined its ability to restore output to pre-civil war levels.

Despite recent military gains by the GNA, the LNA still controls the eastern terminals of Es Sider, Ras Lanuf, Brega, Zueitina and Marsa el Hariga. That means some two-thirds of Libyan crude, or around 800,000 b/d, remains offline.

http://plts.co/9yaQ50A3Yb4

London — Freight rates for Aframaxes in the Baltic and UK Continent have plunged to multi-year lows as a fall in regional oil demand has been exacerbated by output cuts and excess tonnage, sources said Wednesday.

Recent interest from European refineries for sweeter crudes has caused US sweet grades such as WTI Midland to attract more buying interest, which could signify more tonnage arriving in the Northwest Europe at the end of July, maintaining pressure on freight rates in the region.

Rates on the benchmark Cross-UK Continent route, basis 80,000 mt, plummeted to over a nine-year low of $5.29/mt or Worldscale 70 on June 9, S&P Global Platts data showed.

Similarly, the Baltic-UKC route, basis 100,000 mt was assessed at w50 or $4.52/mt on June 9, the lowest rate on this voyage since September 5, 2017, according to Platts data.

Sources said rates were so low for a myriad of reasons, starting from a lack of cargoes which was due to both weak European demand along with production cuts by Russia and Norway, which had steadily reduced their monthly oil loadings.

According to the Russian Urals program for July, scheduled loadings will be the lowest in eight years, with only 24 cargoes of 100,000 mt each predicted to load from Primorsk, where the bulk of the Urals program usually loads. In April, loadings from Primorsk totaled 39 cargoes of 100,000 mt each.

Secondly, there was a lot more North Sea and Russian crude going East on VLCCs and this was draining liquidity from the Aframax routes.

"The market is in free fall," said a shipbroker. "We should be getting close to the bottom, but I feel maybe it could still go a few points as owners are getting close to or just below operational levels apparently."

The lack of demand meant growing tonnage was a huge concern.

"There is just so much tonnage. We have 18 prompt ships today and that gets topped up to 22 tomorrow," a second shipbroker said.

"I think the second decade [of June] of Baltic Urals is covered and most of the North Sea crude is going on VLCCs or on an own-program basis so there is very little to play with," he said.

Sources said trading was likely to remain slow this week unless some charterers started fixing some stems for the last 10 days of June to snap up the excess tonnage, although this was unlikely.

http://plts.co/V3HE50A3PP2

Tokyo — Japan's crude throughput rose for the first time in seven weeks as domestic gasoline demand has recovered to a pre-state of emergency level but local traders remain cautious about the sustainability of the demand recovery with the rainy season approaching when driving typically slows.

"We do feel [the gasoline demand] is recovering," a source with a Japanese refiner told S&P Global Platts June 10. "We cannot adjust [refinery runs] swiftly but it is moving toward increasing it."

Japan's crude throughput rose 5.3% week on week to 1.92 million b/d over May 31-June 6, with its refinery utilization rates having also increased from 51.8% a week earlier to 54.5% of overall capacity, the Petroleum Association of Japan said on June 10.

The May 31-June 6 crude throughput marked the first week-on-week increase in seven weeks since the country's crude processing volume last increased in the week of April 12-18.

"Japan refinery run rates are not high at the moment, the gasoline demand is recovering but not enough to [really increase overall] operations," a Japan-based naphtha trader said, noting that the current overseas markets are not supportive to increase middle distillates output for exports.

"Gasoline demand is better than expected, so refiners need to produce or import gasoline, and they can just use a secondary unit like an RFCC or FCC to produce more gasoline," the trader said, adding that naphtha was currently not in demand for gasoline blending.

Several Japanese refineries are also slated to be restarted in coming weeks from scheduled and unscheduled shutdowns.

Demand recovery

Japan's estimated gasoline shipments rose 7.5% from a week ago to June 6 to 5.04 million barrels, a level above the pre-state of emergency level of 4.72 million barrels over April 5-11, according to Platts calculations based on the PAJ data.

The domestic gasoline demand has been recovering in recent weeks during weekends, following the lifting of the state of emergency, which was declared April 7 to curb the spread of the coronavirus pandemic, on May 25 after bottoming out during the Golden Week national holidays over late April to early May, according to local market sources.

In a sign of demand recovery, a record number of gasoline cargoes was traded during the Platts Market on Close assessment process for Japan's domestic rack gasoline assessments on June 10. A total of 33 deals of 50 kl cargoes was traded for 1,650 kl or 10,378 barrels of gasoline, the highest since Platts launched the domestic assessments in December 2016.

On June 10, Japan's domestic gasoline rack prices in Chiba, east of Tokyo Bay, stood at Yen 38,500/kiloliter ($57.04/b), up 37% or Yen 10,400/kiloliter from May 25 when the state of emergency was lifted, Platts data showed.

A number of Japanese traders, however, remained cautious on the outlook for a gasoline demand recovery as most of the country is entering the rainy season in coming weeks, when the demand could be impacted by bad weather.

Sustained pickup

Regionally, the gasoline demand has shown signs of a sustained pickup with more countries easing lockdown restrictions.

Since-mid May, driving activity from Southeast Asian countries such as Vietnam and the Philippines has been on a steady rise, according to mobility data from Apple.

The increase in activity had even prompted companies in these countries to seek a total of around 1.8 million barrels of gasoline on the spot market in June, according to open tenders seen by Platts. The recovery is expected to gain steam in the near term with Malaysia and Indonesia both easing lockdowns this week.

Reflecting the improved sentiment, the FOB Singapore 92 RON gasoline crack against front-month ICE Brent crude futures on June 10 was assessed at plus $2.48/b, a sharp jump from minus $1.38/b seen on June 1, Platts data showed.

http://plts.co/B0PQ50A3O2t

Houston — Enterprise Products Partners' planned Sea Port Oil Terminal offshore of Houston is facing new delays now that the federal government has stopped the clock on the licensing process to allow Enterprise more time to answer questions and provide additional information.

The regulatory US Maritime Administration said it suspended the timeline for the SPOT project that is the leading contender to be the first deepwater Texas terminal built to export crude oil around the world.

"SPOT provided some responsive information but also notified the US Coast Guard that additional time would be needed to fully respond," MARAD noted in a new letter to Enterprise.

The delay is not particularly surprising because Enterprise said in late April that it no longer expected to receive federal approval for SPOT in 2020 amid the coronavirus pandemic and the global collapse in crude oil demand. Enterprise had previously planned to start construction as soon as this summer and open the terminal in 2022 after receiving its federal license no later than June. However, the two-year construction timeline now pushes the project's completion to at least 2023.

Enbridge partnered with Enterprise on the SPOT project in December -- abandoning its competing Texas COLT project in the process -- and Chevron already is signed on as the anchor customer.

SPOT is proposed to be built about 30 miles offshore of Freeport, which is due south of Houston. The deeper-water depths offshore are needed for Very Large Crude Carriers to load up to capacity. SPOT would be able to load 2 million b/d and simultaneously two VLCCs at a time.

Enterprise has remained committed to the project though.

"The company is working on addressing information requests from USCG/MARAD, reviewing submittals from the public comment period, as well as other input from landowners and public officials," Enterprise spokesman Rick Rainey said in a late June 8 statement. "This work includes evaluating options to meet our business needs while mitigating concerns that have been expressed. We are in regular communication with USCG/MARAD and other federal and state regulators to help assure that these considerations are integrated smoothly into the permitting process."

MURKY WATERS

The project has faced opposition from environmental groups and some local communities.

As of early this year, there was a race to build the first deepwater oil exporting terminals offshore of the crude oil hubs near Houston and Corpus Christi. However, the coronavirus pandemic has put that race on hold -- if not canceling the race outright.

Multiple proposed offshore oil-exporting terminals already were shelved or merged with other projects even before the pandemic.

The only other project with substantial backing thus far is Phillips 66's and Trafigura's planned Bluewater terminal offshore of Corpus Christi.

Pearce Hammond, a midstream analyst with Simmons Energy, questioned on June 9 whether any of them will be built.

"The bigger issue at this point, in our view, is how needed is the terminal in light of the changed dynamics for the US oil market post COVID?" Hammond stated in a note. "Does the terminal get built because it is a much cheaper and more efficient means of exporting crude (and replaces existing less efficient crude export terminal capacity), or does the terminal not get built because the global need for higher US crude exports has been redefined lower post COVID? Time will tell."

Already, US crude exports in 2020 have fallen from a high of 4.38 million b/d for the week ending March 13 down to 2.79 million b/d for the week ending May 29, according to the US Energy Information Administration. And analysts project crude export volumes to further plunge in the coming months.

Only one Gulf of Mexico port, LOOP, can fully load VLCCs currently without lightering from smaller vessels. However, LOOP was built primarily for imports and has only more recently added crude-exporting capacilities.

http://plts.co/EiSX50A3mSl

The U.S. shale-oil industry may collapse due to the sharp fall in oil prices because of the coronavirus pandemic, a new influential report predicts.

The demand for and price of oil tumbled due to the economic slowdown and have since begun to recover, but Australian think tank the Institute for Economics and Peace warns that a low price will affect political regimes in the Middle East, especially in Saudi Arabia, Iraq and Iran.

“ The impact of coronavirus may ‘result in the collapse of the shale oil industry in the U.S., unless oil prices return to their prior levels.’ ” — Institute for Economics and Peace

IEP’s annual Global Peace Index, published Wednesday, analyzes tension around the world and compiles an index of the most peaceful countries. It suggests the effects of the pandemic may “result in the collapse of the shale-oil industry in the U.S., unless oil prices return to their prior levels.”

While the price of oil CL.1, +0.43% has begun to recover from its nadir — having crashed into negative territory in April — analysts at Goldman Sachs warned in a Tuesday note that the rise in the oil price has been overdone and forecast a drop in Brent crude prices BRNQ20, -1.03% to $35 a barrel, from around $43 a barrel, within weeks.

Shale oil is produced through fracking, the controversial process of pumping high-pressure water and sand underground to fracture rock and release valuable new energy reserves known as shale.

Among the biggest producers of shale oil are Exxon Mobil XOM, -4.50% , Chevron CVX, -2.77% and EOG Resources EOG, -4.96% .

The IEP report says that the combined weakness in commercial, travel and industrial activity led to a plunge in oil prices in global markets. “These markets were already affected by an oversupply, emanating from Russia and Saudi Arabia who could not agree on production curbs,” it says.

But, on a positive note, it goes on to rank the countries most likely to stage a swift economic recovery in the wake of the pandemic, using four indicators.

China, Indonesia, Russia, Mexico and Australia all emerge as best placed to facilitate a recovery because they have low unemployment rates, low dependence on international trade, low tax revenue relative to gross domestic product, and low central government debt as a proportion of GDP.

IEP founder Steve Killelea said: “COVID-19 is negatively impacting peace across the world, with nations expected to become increasingly polarized in their ability to maintain peace and security. This reflects the virus’s potential to undo years of socioeconomic development, exacerbate humanitarian crises, and aggravate and encourage unrest and conflict.”

He identified a predictable list of sectors hurt by the lockdown, which includes aviation, hospitality, tourism, retail and finance. Health care, telecom and food production are best placed.

One upside is that drug trafficking and other types of crime have seen a likely temporary reduction as a result of social isolation around the world. However, reports of domestic violence, suicide and mental illness increased.

Iceland remains the most peaceful country in the world, a position it has held since 2008. It is joined at the top of the index by New Zealand, Austria, Portugal and Denmark.

Afghanistan remains the least peaceful country, a position it has held for two years, followed by Syria, Iraq and South Sudan.

“The fundamental tensions of the past decade around conflict, environmental pressures and socioeconomic strife remain,” Killelea said. “It’s likely that the economic impact of COVID-19 will magnify these tensions by increasing unemployment, widening inequality and worsening labor conditions — creating alienation from the political system and increasing civil unrest. We therefore find ourselves at a critical juncture.”

https://www.marketwatch.com/story/the-us-shale-oil-industry-may-collapse-new-report-says-after-goldman-warns-crude-is-set-for-a-fall-2020-06-10%3Flink%3DMW_latest_news&ct=ga&cd=CAIyHDM2NzYyZTdmOGQyMDc4MGI6Y28udWs6ZW46R0I&usg=AFQjCNHPvf7EvsjdzQiO58XgYYb5ncTUt

(Bloomberg) -- Venezuela’s fall from oil superpower to failing producer can be illustrated in one image: a single drilling rig working the world’s largest oil reserves.

As fields across the nation shut amid a relentless U.S. campaign to cut Venezuela off from global oil markets, the number of rigs drilling for crude fell to just one in May, according to data from Baker Hughes. Another lone rig was drilling for gas.

That marks a 96% decline since January, when drilling fell to levels not seen since 1963. Having a single active crude rig takes the country back to the beginning of its oil industry, well before it became a founding member of the Organization of Petroleum Exporting Countries. The development underscores the toll that U.S. sanctions have taken on the nation as President Donald Trump escalates efforts to remove Venezuelan President Nicolas Maduro from power.

State-owned oil company Petroleos de Venezuela SA has been gradually shutting fields due to fewer buyers, low prices and lack of both investment and personnel. In May, about one-third of the 77 oil fields across the country were producing zero barrels and more than 10% pumped less than 500 barrels per day, according to PDVSA production data seen by Bloomberg. Many of the shuttered fields are joint ventures between PDVSA and foreign partners including China’s CNPC, Cubas’ Cupet or Angola’s Sonangol.

The last remaining rigs in Venezuela were located at the Maracaibo basin and the Orinoco Oil Belt, operated at PDVSA joint ventures, according to people familiar with the matter. Production has been dropping steadily over the years to historic lows. PDVSA total oil production in May decreased 16% to 645,700 barrels a day. The bulk of that output came from the Orinoco Belt which produced 332,700 barrels daily barrels, according to a document seen by Bloomberg.

The downturn in production has culminated in a nationwide fuel crisis, with local refineries unable to churn out enough gasoline and diesel to meet demand, even as a national quarantine depresses consumption. At the same time, gasoline imports have been curtailed by U.S. sanctions against Rosneft PJSC and shipping agencies that once swapped fuel for crude with Maduro’s cash-strapped government. Recently, gas pumps have seen a brief reprieve after five vessels carrying Iranian fuel discharged at local ports.

https://finance.yahoo.com/news/venezuela-single-oil-rig-works-100000736.html

Bullish sentiment appears to have returned to the stock markets with a vengeance. In a historic rally that has taken even die-hard bulls by surprise, the S&P 500 has managed to claw back all of its 2020 losses, taking just 53 sessions for the index to fully restore the nearly $10T in value it shed in an epic bear market. The oil markets have been nearly as impressive.

After entering negative territory for the first time in history, U.S. WTI prices have briefly touched $40/bbl amid record production cuts and an uptick in global demand. Oil and gas stocks have doubled from their March 23 nadir, marking a sharp reversal from the precipitous drop that wiped out nearly two decades of gains.

There’s no shortage of bottom fishing opportunities in this market, with shares of bankrupt or near-bankrupt shale companies including Whiting Petroleum (NYSE:WLL), Chesapeake Energy (NYSE:CHK), California Resources Corp. (NYSE:CRC) and Valaris Plc (NYSE: VAL) as well as offshore drillers Borr Drilling Ltd (NYSE:BORR), Noble Corp.(NYSE:NE), Seadrill (NYSE:SDRL) and TransOcean (NYSE:RIG) recording triple-digit gains over the past week alone.

But analysts are now saying investors need to pump their brakes.

A cross-section of Wall Street has warned that there’s too much irrational exuberance in the markets, and the oil price rally is not fully supported by fundamentals.

Watching the Crack

According to Warren Patterson, head of commodities strategy at ING, as well as analysts at Goldman Sachs, refining margins, aka crack spreads, across different regions around the globe are still way off their norms, portending continuing weak global demand for distillates.

U.S. crack spreads clocked in at a mere $9/bbl last week, compared to $21 at the same time last year according to Reuters, while crack spreads for European diesel dropped to a record low of $2.90

Crack spreads are a good proxy for oil demand with falling spreads a sign of weak demand and vice-versa. The badly squeezed margins for refiners is a worrying sign that global demand remains way below normal levels, with the ongoing pick-up in crude prices only serving to worsen the margin contraction for the likes of Valero Energy Corp. (NYSE:VLO), Marathon Petroleum Corp. (NYSE:MPC) and Phillips 66 (NYSE: PSX). WTI and Brent prices have staged a strong rally over the past few weeks after production cuts by OPEC+ and independent producers in the U.S. and elsewhere helped ease a huge supply glut and storage buildup.

On Saturday, OPEC and its allies agreed to extend the cuts by an additional month with plans to review progress on a monthly basis. Global oil demand particularly in the giant markets of China and India appears to be recovering at a faster-than-expected clip, with crude imports in China surging 13% in May to a record 11.3 million barrels per day and demand back to 90% of pre-crisis levels. Meanwhile, May sales in India were recorded at ~76% of normal levels while U.S. gasoline demand has seen a 7% uptick during the final week of May to clock in at 75% of pre-COVID-19 levels.

But analysts are now questioning whether the rebound in demand is the result of rising consumption or simply the result of refiners and traders stocking up on cheap crude.

ING’s Patterson and Ehsan Khoman at Japanese bank MUFG say the surge in demand could partly be the result of opportunistic buying by refiners. Consequently, Goldman has predicted that Brent prices will pull back to $35 per barrel in the coming weeks from a recent high of $43.

And they could be right.

According to Bloomberg, the United States’ largest refiner by capacity, Valero Energy, is currently running its two crude units at just 58% of their maximum rate of 424K bbl/day due to low demand and storage filling up. The refinery's fluid catalytic converter as well as all the hydrotreaters except the distillate hydrotreaters are running at minimum rates while rates on the coker have also been lowered.

In a previous article, we reported that giant oil traders have been storing millions of barrels of crude in the seas with a view to selling when prices improve in the coming months, which could also be driving the surge in demand.

Takeaway

At this juncture, it’s best for investors to adopt an attitude of cautious optimism. On one hand, the bulls argue that OPEC+ has curtailed production too fast, with some oil executives eyeing the seemingly untouchable WTI prices of $70 in the current year.

On the other hand, poor refining margins are telling a different story while oil prices have, worryingly, been strongly pulling back from recent highs on fears that increased production by U.S. shale producers and Libya will offset the OPEC+ cuts.

As many analysts have pointed out, the biggest wild card in this market remains the speed at which demand is going to bounce back in the coming months.

The current evidence though appears to lend support to the bull camp.

http://www.baystreet.ca/articles/commodities/57749/061120&ct=ga&cd=CAIyHGU1MmVjNzQwMjI3M2I5Y2E6Y28udWs6ZW46R0I&usg=AFQjCNGP16M4qDtF_7cail_M0hyavm0tS

With effect from 6 am,petrol and diesel prices were increased by 60 paise per litre each in Delhi

Petrol and diesel prices were hiked in metros on Thursday, marking the fifth straight day of increase since state-owned oil companies returned to the normal practice of daily reviews following a 12-week pause. With effect from 6 am, the prices of petrol and diesel were increased by 60 paise per litre each in Delhi. While the price of petrol was revised to Rs 74 per litre in the national capital from Rs 73.40 per litre the previous day, the diesel rate was increased to Rs 72.22 per litre from Rs 71.62 per litre, according to notifications from state-run Indian Oil Corporation, the country's largest fuel retailer. (Also Read: How To Find Latest Petrol, Diesel Rates In Your City)

Here are the current petrol and diesel prices in metros (in rupees per litre):

International oil prices fell more than 2 per cent on Thursday on worries about slow demand growth with coronavirus cases rising, US crude stockpiles hitting an all-time high and the Federal Reserve projecting recovery from the pandemic would take years. Brent crude futures - the global benchmark for crude oil - fell 2.2 per cent to $40.81 per barrel, giving up all of the gains registered the previous day.

State-run oil marketing companies revise the prices of petrol and diesel from time to time, besides aviation turbine fuel (ATF) - or jet fuel - and liquefied petroleum gas (LPG). However, since March 16, the oil companies had kept petrol and diesel prices on hold, possibly due to the volatility in global oil markets.

Fuel retailing in the country is dominated by state refiners - Indian Oil Corporation, Bharat Petroleum Corporation and Hindustan Petroleum Corporation. The three own about 90 per cent of the retail fuel outlets in the country.

https://www.ndtv.com/business/petrol-price-today-diesel-price-today-fuel-rates-hiked-for-fifth-straight-day-after-3-month-pause-2244275&ct=ga&cd=CAIyGjFhODM5OTgwNmE5N2Q2NjA6Y29tOmVuOkdC&usg=AFQjCNEeTguNUxmYtqQGw_AhUdvsOXGaV