قال سفير ايران لدى نيودلهي علي جكيني: إن الجمهورية الاسلامية الايرانية طرف موثوق به قادر على توفير الطاقة للهند، مؤكداً أن الهند لا تتجاهل هذا الواقع.

وفي تصريح له لصحيفة (إينديا تايمز)، أضاف جكيني: ان الهند ستتخذ قرارها بشأن استيرادها النفط وفق أمنها القومي وحاجتها الى الطاقة، مشيراً الى العلاقات الثنائية بين البلدين والمشتركات الممتدة الى قرون سابقة.

واعتبر سفير ايران لدى نيودلهي الحظر المتفرد الأمريكي نقضاً لسيادة وحرية الدول المستقلة، لافتاً الى حق ايران في تصدير النفط وإلى عدم استطاعة أي طرف منعها عن تصدير النفط.

وتطرق جكيني، خلال المقابلة، الى مواصلة التعاون بين ايران والهند في تنمية ميناء جابهار، وقال: إن الكثير من الدول راغبة في الاستثمار في جابهار نظراً لإيلاء ايران أولوية لذلك.

وأعرب عن اعتقاده بأن الهند لاعبة مركزية في الساحة الدولية وفي المنطقة وقادرة على توظيف آلية الدبلوماسية والحل السلمي لحث الدول على إقامة العدالة. وتعتبر الهند بعد الصين ثاني أكبر بلد يشتري النفط من ايران، حيث بلغ حجم النفط الذي إشترته من ايران الى 24 مليون طن حتى نهاية العام المالي في 30 مارس

al-vefagh

http://www.tehrantelegram.com/story-z23387616

Four commercial vessels were targeted by "sabotage operations" near the territorial waters of the United Arab Emirates, the UAE foreign ministry said in a statement on Sunday, adding that there were no victims.

"Subjecting commercial vessels to sabotage operations and threatening the lives of their crew is considered a dangerous development," the ministry said in a statement that was tweeted by the official news agency WAM. 

Saudi Arabia's Energy Minister Khalid al-Falih said on Monday that two Saudi oil tankers were targeted on Sunday in "a sabotage attack" off the coast of Fujairah, part of the United Arab Emirates, threatening the security of global oil supplies. 

Iran's response:

In response, Iran's foreign ministry spokesman Abbas Mousavi called the incidents “worrisome and dreadful”, and asked for an investigation into aspects of the matter.

Mousavi was cited by the semi-official ISNA news agency as saying “such incidents have negative impact on maritime transportation security”, and asking for regional countries to be “vigilant against destabilizing plots of foreign agents."

U.S. refiners had a plan for 2020: use their complex operations to maximize profits by making products that would comply with new international laws capping sulphur content in shipping fuels.

But after a series of unexpected market moves, heavy, sour crude oil processed by U.S. refiners has become more expensive, eating up hoped-for profit windfalls before they even materialized, forcing refiners to rethink plans to invest more in heavy crude processing units.

New regulations by the International Maritime Organization (IMO) will require ships globally to use fuels with a sulphur content below 0.5% beginning in 2020. Current shipping fuel is much dirtier, with a higher sulphur content.

The move was expected to make heavy crude oil cheap as most refiners worldwide shifted to lighter crudes that yield compliant lower-sulphur fuels - and benefit complex U.S. refiners that possess greater capability to break down that heavy crude into high-margin products.

Instead, global heavy crude supplies have become scarce due to sanctions on Venezuela, one of the world’s biggest heavy producers, pipeline bottlenecks in Canada and OPEC output cuts. The Organization of the Petroleum Exporting Countries’ April output fell to 30.23 million barrels per day (bpd), the lowest since 2015.

“The biggest single factor is the big loss of heavy crude,” said Todd Fredin, executive vice president of supply, trading and logistics at Motiva Enterprises, which operates a 603,000 bpd operation in Port Arthur, Texas, the largest U.S. refinery. The benefit to complex refiners from the regulatory change “is going to be less than people thought,” he said.

Heavy crude once fetched a big discount compared with light crude, but it has narrowed after sanctions on Iran and Venezuela. That weighed on first-quarter earnings for major independent refiners Valero Energy Corp and Phillips 66 .

Marathon Petroleum Corp this week halted plans to add a coking unit to its Garyville, Louisiana refinery that would have processed more heavy crude. Marathon said the coker, which was expected to come online in 2021, was no longer financially viable due to narrowed spreads.

U.S. refiners rely on cokers to break down residual oils into other refined products, including gasoil and naphtha. Refineries without that capability typically process more light crude, produced in abundance by the United States, versus heavy crude, which U.S. refiners have to import.

The price difference between U.S. Gulf Coast grades Louisiana Light Sweet (LLS) and Mars, the best proxy for comparing light, sweet and heavy, sour crude in the U.S. Gulf, has narrowed in the last few months.

LLS’s premium over Mars on Thursday was $2.05 per barrel, compared to $4.25 per barrel in mid-November, according to Refinitiv Eikon data. At one point in February, Mars traded at a premium to lighter LLS, the first time that has happened since 2011.

Some analysts said crude volumes processed may have to be cut, but so far that has not happened. “We really see the narrowing of the spreads to be a short-term issue,” Marathon Chief Executive Gary Heminger told Reuters, saying the company is keeping their existing coking units full.

Prices of heavy crude will likely remain high as traditional heavy suppliers like Canada and Mexico grapple with infrastructure and production constraints, said Michael Tran, an analyst at RBC Capital Markets.

“There’s not many countries that can step up to the plate” to make up for the loss, he said.

https://uk.reuters.com/article/usa-refiners-imo/u-s-refiners-2020-plans-could-shift-as-heavy-fuel-becomes-expensive-idUKL3N2263ZE

Oil refiners across Asia are bidding up crude prices from Abu Dhabi to Oman as they compete for supplies to make up for lost Iranian and Venezuelan exports.

July-loading cargoes of grades such as Murban and Das were bid at premiums of $0.80 to $0.85/bbl above the official selling price on Friday on an electronic trading platform operated by S&P Global Platts. That would be the highest spot differentials in at least three years for the grades, according to data compiled by Bloomberg. Upper Zakum crude was also bid at a $0.65 premium, while Umm Lulu changed hands at a $0.95 premium. The higher bids came even after Abu Dhabi National Oil hiked the official price of its crude earlier this week.

Buyers across the world’s top oil-importing region are scrambling for oil as U.S. sanctions on Iran and Venezuela tighten supplies of high-sulfur crude that their refineries are designed to process. Unplanned disruptions to Russian and Nigerian flows and concerns that fighting in Libya could affect oil exports also contributed to the fervor to secure cargoes.

Oman crude futures climbed to a premium of $3.10/bbl over swaps for Dubai oil, the benchmark grade for the Middle East. That’s its highest premium since September, when markets were spooked by the prospect of U.S. sanctions putting an end to Iranian exports.

A wide discount between the Dubai benchmark and Brent, the marker for more than half the world’s oil supplies, is also contributing to the strong interest for Middle Eastern grades. Dubai’s discount to Brent futures was more than $3/bbl on Friday, near the highest level in seven months.

https://www.worldoil.com/news/2019/5/10/middle-east-oil-grab-hits-fever-pitch-as-supply-squeeze-persists

Investor Drexel Hamilton Infrastructure Partners LP and rail operator Rio Grande Pacific Corp on Friday disclosed plans to build a $1.5 billion rail line that would transport heavy crude from Utah to connections to the U.S. Gulf Coast.

Drexel Hamilton and Rio Grande officials said the project aims to deliver about 400,000 barrels per day (bpd) of Uinta basin crude to Gulf Coast refineries looking to replace heavy oil supplies from Venezuela.

“The Uinta has only been restricted from Gulf Coast and overseas refiners as a result of limited takeaway capacity,” said Mark Michel, a managing partner at private equity fund Drexel Hamilton. “We are going to change that.”

Uinta Basin oil now is trucked to Salt Lake City refineries because it is too thick to put into a pipeline, Robert Bach, president of Rio Grande said in an interview. “This (Gulf Coast) market is much bigger.”

The proposed project would include at least one terminal able to load crude onto trains and to receive sand used in hydraulic fracturing. The rail line will be contingent on receiving commitments from oil producers, Bach said.

The Seven County Infrastructure Coalition, a Utah regional planning group, on Friday approved terms of a preliminary agreement with Drexel Hamilton to build the railroad.

Rio Grande owns four short-line railroads in Texas, Louisiana, Oklahoma and other states. The proposed rail line would extend 80 miles between connections with Union Pacific and BNSF Railway near Soldier Summit, Utah and potential terminal locations in the Uinta basin near U.S. oil producers.

“There was never enough momentum behind this before,” Bach said, explaining that U.S. sanctions on Venezuela’s state-run PDVSA oil company, a former major supplier of heavy crude to the U.S., helped spur demand.

https://www.reuters.com/article/us-usa-crude-rail/rail-operator-proposes-to-move-utah-heavy-oil-to-u-s-gulf-coast-idUSKCN1SG2EB

The U.S. Coast Guard said on Saturday it’s too early to estimate when the Houston Ship Channel can reopen after a collision that spilled about 9,000 bbl of a gasoline ingredient into the water.

Friday’s collision involved the tanker Genesis River and a tug transporting two barges carrying more than 2 million gallons of reformate, an oil-refining byproduct used to make gasoline. One barge capsized and the other was damaged following the incident that occurred 2 1/2 mi east and south of the Bayport terminal.

“Our objective today is to secure the vessels,” U.S. Coast Guard Captain Kevin Oditt told reporters. “Once we have those vessels secured, we will work with the pilots and we will evaluate whether we can reopen the ship channel.”

The Houston Ship Channel is the city’s lifeline to the Gulf of Mexico and to foreign markets. Oil shippers, refiners, chemical manufacturers and grain exporters rely on the waterway to receive and deliver everything from crude to corn.

The Coast Guard established an emergency temporary safety zone and closure of the Clear Creek Channel from the entrance to Clear Lake extending east to Light 66 and north up to but not including the Bayport Ship Channel, it said in a statement. The area between Light 61 and Light 75 was also shut.

The spill was pinpointed by the National Weather Service as a possible source of the gasoline-like scent wafting across Houston’s eastern suburbs. Teams of air monitors were working around the clock to assess levels.

“To date, those teams have taken over 1,300 samples and, in all cases, the samples taken have not exceeded the established action levels,” said Craig Kartye of the oil spill prevention and response program at the Texas General Land Office.

About 3,600 ft of boom has been put in place and efforts are underway to deploy an additional 12,000 ft in the most pressing areas, said Jim Guidry, executive vice president of vessel operations for Kirby Inland Marine, operator of the tug involved.

While one of the barges has lost about 9,000 bbl of reformate, the capsized vessel hasn’t leaked any cargo at this time, he said.

“We are continuing to work with the Coast Guard and the other federal regulators to understand the cause of the incident and will be working to recover any of the spilled product and mitigate the impact on the environment,” Guidry said.

https://www.worldoil.com/news/2019/5/12/houston-ship-channel-still-not-safe-for-passage-to-gom-after-oil-spill

Norwegian oil and gas player Aker BP has failed to find hydrocarbons after drilling a wildcat well in the North Sea offshore Norway.

The Norwegian Petroleum Directorate (NPD) said that the well 25/11-29 S was drilled on the Utsira High, about 14 kilometers south of the Grane field and 190 kilometers west of Stavanger in the central part of the North Sea.

The primary exploration target for the well was to prove oil in reservoir rocks of Early Jurassic age in the Statfjord group. The secondary exploration target was to prove oil in reservoir rocks of Paleocene age in the Heimdal formation.

The well encountered the Statfjord group with a thickness of about 100 meters, of which 65 meters is reservoir rocks with good reservoir quality. The well did not encounter the Heimdal formation. The well is classified as dry. Extensive data acquisition and sampling have been carried out.

It is worth noting that this is the first exploration well in production license 916 which was awarded in APA 2017.

The NPA added that the well was drilled to vertical and measured depths below the sea surface of 2,233 and 2,283 meters respectively, and was terminated in the Zechstein group of Permian age. The well will be permanently plugged and abandoned.

Well 25/11-29 S was drilled by the Deepsea Stavanger drilling rig, which will now proceed to production license 777 in the central part of the North Sea to drill wildcat well 15/6-16 S, where Aker BP is the operator.

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https://buff.ly/305OkQF

A tiny South American country until recently known mostly as the location of one of the worst mass suicides in modern history is about to acquire a whole new reputation, and this reputation has to do with its oil wealth.

Guyana, sandwiched between Venezuela and Suriname, has in just a couple of years turned from an empty spot on the international oil map into one of the new hot spots thanks to a series of discoveries offshore, made by Exxon and Hess Corp.

The Stabroek block is the place where the discoveries were made. The first ones came in 2015 and since then, Exxon has been announcing new ones on a more or less regular basis. To date, there have been 12 discoveries, with the reserves associated with them topping 5 billion barrels of oil equivalent.

This is certainly a lot of oil and it could either solve all economic problems of the tiny nation of less than a million people or, as history has sadly proved more than once, become an oil curse. It would all depend on how Guyana handles its future oil wealth.

The BBC’s Simon Maybin noted in an analysis of Guyana’s changing fortunes this week that the country, a former British colony, currently suffers high unemployment and poverty rates. It also has high levels of corruption—a practice that oil wealth has been found to exacerbate more often than not. The billions of dollars in oil revenues to be had also encourage political instability as more groups vie for power and access—preferably exclusive—to the oil dollars.

Already, sings of this political instability are emerging in Guyana, Maybin reports. The coalition in power lost a no-confidence vote last December, but instead of calling elections, which would have been standard procedure, the coalition challenged the result of the vote in court. This has led to demonstrations and a prolonged legal battle that is still not over.

Guyana’s only hope is if it can somehow manage to put a lid on political ambitions and focus on the actual benefits to be reaped when Exxon and Hess begin commercial production, such as improving the living conditions of the poorest Guyanese and reducing unemployment as well as boosting economic growth. Related: Oil Markets Uncertain As Trade War Counters Supply Shortages

Luckily, Guyana has both good and bad examples to look to. Norway is the best good example of how a nation can use its oil money in a productive way and turn into one of the wealthiest in the world without relying excessively on oil but rather on the smart investments of money from this oil.

And then there’s Guyana’s very own neighbor Venezuela, which is a picture of how it shouldn’t be done, namely by neglecting other sectors of the economy in favor of oil, pouring oil money directly in otherwise good social programs and seeing them crumble along with the economy once oil prices drop. Corruption and the resulting authoritarianism to keep control of the oil money are also among Venezuela’s problems that predate the U.S. sanctions. Now, the country is shaken by a perfect storm that could see its oil production obliterated.

So, the world’s new hot spot could either turn into a new Norway or a new Venezuela, Nigeria, Angola, and a host of other countries for whom oil turned from a blessing into a curse. It seems only time will tell which example the country will follow.

By Irina Slav for Oilprice.com

More Top Reads From Oilprice.com:

https://oilprice.com/Energy/Energy-General/Could-This-Emerging-Oil-State-Become-The-Richest-Nation-In-The-World.html&ct=ga&cd=CAIyGjk5YzNmM2Y0NmU2Yjk4MTk6Y29tOmVuOkdC&usg=AFQjCNFbENlRaQ7usjGrioUr6xz9mm-Hi

TEHRAN - Visiting Research Scholar in the CESP Omid Shokri believes that even with massive inspections the U.S. will not be able to drive Iran’s oil export to zero.

To drive Iran’s oil export to zero, the Trump administration said that it will no longer exempt any countries from U.S. sanctions if they continue to buy Iranian oil, stepping up pressure on Iran in a move that primarily affects the five remaining major importers: China and India and U.S. treaty allies Japan, South Korea, Turkey.

To shed more light on the issue we dissussed it with Omid Shokri Kalehsar a Washington-based Senior Energy Security Analyst.

Here is the full text of our interview with him:

Q: Saudi Arabia and the UAE have announced they will compensate for Iranian oil. Is this possible technically?

A: Supply and demand is an important factor in the international oil market. The oil market needs increased supply from major OPEC members and non-members such as Russia. It seems that Saudi, the UAE and Iraq with Russia must produce more oil to overcome the shortage of Iranian oil in the oil market. At present major importers of Iranian oil are looking to find an alternative to Iranian oil because the U.S. did not extend the waiver for Iran’s major oil buyers. India and South Korea are importing more oil from the U.S. and also imported more US LNG, refineries from these both countries are adapting themselves to U.S. oil, they previously imported Iranian oil and are now ready to import U.S. oil. Some analysts believe that the Saudis will be faced with the major problem of increasing their oil output by as much as a million barrels; Saudi Arabia's oil consumption is rising in the warm months due to increased cooling applications and oil consumption rises from 400 to 500,000 bpd.

It is claimed that the other barrier which Saudi Arabia faces in increasing its crude exports is that the government have invested heavily in their refineries and oil products exports over the past years. A unilateral increase in oil output beyond the quotas could impose a requirement for other OPEC members and even eliminate the agreement between OPEC and 10 OPEC non-member countries.

It will possible for Saudi to increase its crude production in the two months of May and June. Saudi Arabia said the country's oil production in the first quarter of this year would be lower than its country's quota, which would allow the country to increase production in those two months. It should be recalled that calculating the compliance of OPEC member states with their oil production quotas is carried out over a six-month period, and the average monthly production of these countries in this six-month period is the basis for judging their compliance with their quotas.

In this way, Saudi Arabia could offset Iranian oil exports from markets by boosting its oil production over the next two months. The decision on the quota for the second six months of this year (July to December) will be taken at the OPEC Ministerial Meeting in Vienna, held in June. Thus, eliminating Iranian oil does not necessarily increase oil prices in the global markets. Some Iranian officials have also confirmed this.

In respect with the United Arab Emirates, which has been proposed as one of the alternatives to Iran's oil market, the country has a production capacity of 3,300,000 barrels per day; its production in 2002 was 2.56 million barrels per day and in 2018 were 3 million and 34 thousand barrels a day. However, according to the latest OPEC announcement, the UAE's oil production in March 2019 amounted to about 3 million and 59 thousand barrels a day. One million barrels will be provided to domestic refineries, and the rest will also be shipped to the export market.

At present some oil producers such as Libya and Venezuela face tensions and political unrest. Currently, aside from Saudi Arabia and the United Arab Emirates, OPEC has no spare capacity. Of course, the commitment to quotas is an important message for the oil market. On the other hand, OPEC or the Consumers' Union is also seriously concerned. If major consumers such as China, India or Turkey form an oil consumer organization, America will not be able to cope with them. Most of OPEC's Middle Eastern countries have focused on Asian markets because the European market has no horizons and the future of the oil market is developing in Asia. In other words, in the current century, they are the largest producers of Asian oil.

Q: The U.S. is making efforts to drive the export of Iranian oil to zero. Is it possible? If not, why?

A: Even a massive inspection will not prevent the sale of quantities of oil. During the Iraqi oil sanctions, despite the international cooperation in this regard, the country was still able to smuggle some of its oil in various ways, including through neighboring countries. Based on this, the U.S. government largely relied on buyer cooperation and fears of a second-round sanction to curb Iran's oil exports. In terms of the oil market, despite the promise of some exporting countries to compensate for any shortages in the market and OPEC's commitment to maintaining price stability in the oil market, full compensation for Iranian oil exports to its technical specifications is not urgent, and given the special discounts that the Iran gives to some importers, small companies who are less concerned about cutting U.S. financial and trading facilities will continue to buy oil shipments.

Some of Iran's oil production is being shipped to China for storage, and part of it is also transported to tankers for informal sales. It seems that Iran could ship 300 to 650 thousand barrels of oil a day, which will not be sold every day. Selling Iranian oil on the grey market is the only way to keep some Iranian share in the oil market. Iran must sell its oil at a low price to find costumers for its oil, while another problem is how to get money from costumers? Another way is for Iranian officials is to sell Iranian oil in the name of another (third) country.

Q: The U.S. is forcing Turkey to stop buying oil from Iran and replace Saudi and Emeriti oil instead of Iranian oil. What are the advantages of Iranian oil for Turkey?

A: The main question for oil traders and political analysts is how much America wants to test these relationships by crippling the Iranian economy. According to the latest official figures available in January, Iran provided more than 12% of Turkey's oil imports. Iraq held 24 percent of the main supply, and Russia provided 15 percent of Turkey's imported oil. Turkey imported only diesel from the UAE in January, and now Iran is the third largest supplier of crude oil for Turkey. 'Iran's oil is not cheap, but there is a major difference in comparison to the prices of Saudi Arabia and the United Arab Emirates,' Turkish Foreign Minister Mevlut Çavusoglu said in Ankara.

Turkey has always defended its commercial ties with its eastern neighbors and considers it a strategic requirement. Iran's oil could be another source of diplomatic controversy between Ankara and Washington, when relations between them are tense due to Turkey's emphasis on purchasing a missile defense system from Russia. Turkey, after some time, will be able to find alternative for Iranian oil; although Turkey prefers to have energy relations with Iran, it seems that Turkey will decrease oil imports from Iran and they may drop to zero in the medium term.

Omid Shokri Kalehsar is a Washington-based Senior Energy Security Analyst, currently serving as a Visiting Research Scholar in the Center for Energy Science and Policy (CESP) and the Schar, School of Policy and Government at George Mason University.

tehrantimes

http://www.tehrantelegram.com/story-z23389338

The lingering oversupply of vessels in the VLCC market has left shipowners weighing options to either idle, reduce sailing speed extensively or take on only short voyages as freight returns are seen below operating costs.

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Sign Up The Time Charterer Equivalent or TCE, which is the earnings accrued, for a modern VLCC has slumped to around $7,000/day on key Persian Gulf to North Asia routes, which hardly covers the daily running cost of the vessel, according to market participants.

To tide over the staggeringly low earnings period, two shipowners told S&P Global Platts that they have resorted to drifting their vessels to save fuel cost. When a vessel is made to drift in a safe location, the power to the main engine is switched off to save on fuel expenses.

"It makes no sense for owners to accept further lower freight levels at the current TCE levels," a VLCC owner said.

Some shipowners are contemplating to avoid working on any cargoes until the freight returns improve to levels that would cover the operating expenses.

"With earnings so low, [a few shipowners are] doing short voyages, so that the pain is over a lesser amount of time. Not everyone can afford to stop ships," a shipbroker said.

The current TCE has fallen massively from levels seen in January, when owners pocketed around $40,000/day.

The anemic earnings are a result of the early onset of the Asian refinery turnaround season along with the slowdown in US crude exports as well as the flood of newbuilding VLCCs during the first quarter of the year.

So far this year 20 new vessels have been added to the VLCC fleet out of the estimated delivery of 54 ships with fewer vessels deleted to offset the tonnage growth.

"Initially, owners will slow steam to cut bunker costs. [Owners are running vessels] at 12-12.5 knots for laden and 9-11 knots on the ballast [leg]," a second shipbroker said.

Meanwhile, shipowners are yet to resort to laying-up of vessels, a strategy adopted when freight levels are insufficient to cover the running costs.

"When the earnings is below $5,000/day, the owners will start laying-up the more expensive ships in the fleet," the second shipbroker said.

"People will not do lay-up now, but just not fix and wait. Waiting is cheap at current rates," a second VLCC owner said.

Some shipowners are compelled to keep their vessels running due to their business models, while others are opting to keep their vessels waiting at Fujairah in the Persian Gulf or Galle at Sri Lanka's west coast, market sources said.

"Slow speed is already happening and people just prefer to wait than fix. What you may see soon is a bit more activity on the VLCC scrapping," a third VLCC owner said, adding that "lay-up is not a usual option and is the last resort".

Despite shipowners with modern VLCCs resisting to fix their vessels, the stiff competition from those with "handicapped" ships has allowed charterers to pick tonnage at very cheap freight levels. The ships coming out of dry-dock and with fewer approvals from oil majors or inspections by marine industry forums are termed as handicapped vessels.

Platts assessed the key PG-China rate at Worldscale 36.5 on Thursday, basis 270,000 mt, which is equivalent to $6.87/mt, down by w26.5 from when Platts had assessed the rate of the same route at w63 on January 2.

https://www.spglobal.com/platts/en/market-insights/latest-news/shipping/051019-tanker-owners-resort-to-idling-vlccs-as-returns-fall-below-operating-costs

Russia has begun shipping clean oil via the Baltic after a contamination problem disrupted flows for three weeks and it is working to resume supplies by a pipeline to Europe although traders said this might take several more weeks to fix.

High levels of organic chloride, used in oil extraction but which must be removed before being sent to clients, was found in crude pumped to the Baltic port of Ust-Luga and through the Druzhba pipeline in late April, disrupting Russian exports.

Two trading sources told Reuters the level of organic chloride in oil loading at Ust-Luga was back to normal on Monday, after the contamination halted sales. Two other sources said test oil shipments via Druzhba had started to Hungary.

Russia’s Energy Ministry had said on Friday tankers were being loaded with clean oil at Ust-Luga, after the disruptions to exports through the port and Druzhba pipeline drove up global crude prices and left refiners as far west as Germany scrambling to find alternative crude supplies.

Two industry sources said Hungarian energy company MOL was receiving oil via Druzhba as part of a test to see whether the equipment at its sole Danube refinery could process the oil. High levels of organic chloride damages refinery equipment.

Hungary has become the first European country to resume imports, but one of the sources said the organic chloride content in Hungary’s test supplies was still above permitted levels of a maximum norm of 10 parts per million (ppm).

The sources said MOL hoped to restart regular Druzhba intakes from May 17, once it had carried out the tests.

Ukraine said on Saturday it had resumed transfers to European clients via the pipeline’s southern leg to Slovakia, Hungary and Czech Republic. The pipeline, which splits into two branches in Belarus, has a northern spur routed to Poland and Germany.

The Czech government approved on Monday a second loan from state oil reserves for refiner Unipetrol, part of Poland’s PKN Orlen group, for more than 100,000 tonnes of crude to cover for supply interruptions from Russia.

“ENORMOUS” COST

Belarus plans to discuss the contamination crisis in the Slovak capital of Bratislava on May 13-14, Belarusian state firm Belneftekhim said on Monday.

President Alexander Lukashenko said last week Belarus had faced “enormous” costs due to the contamination and expected compensation from Russia, although the mechanism for any compensation and who will pay remains unclear.

Russian pipeline monopoly Transneft blamed unnamed “fraudsters” for the problem. Russian President Vladimir Putin said Transneft lacked a proper mechanism to prevent contamination.

The issue has driven down Russian oil shipments. About 6% less oil was pumped through Transneft’s pipeline network from May 1 to May 12 compared with April’s average, two sources familiar with the shipment data said.

They said oil intake in Transneft’s nationwide network, which handles about 85% of Russia’s total crude output, was about 8.8 million barrels per day (bpd) in the 12-day period, citing data that included oil used at home and export volumes.

At least 5 million tonnes of oil, or about 36.7 million barrels, was tainted with high levels of organic chloride.

Transneft has proposed mixing tainted oil with the clean crude at the Black Sea port of Novorossiisk. Industry sources said levels of the organic chloride at Novorossiisk had risen since early May but remained below 10 ppm limit.

Total Russian oil production has also slipped this month, declining to 11.16 million bpd from May 1 to May 12 from an average of 11.23 million bpd in April, sources said, the lowest output level since June, when it was 11.06 million bpd.

Russia has agreed with the Organization of the Petroleum Exporting Countries and other producers to lower output to shore up global prices, but its May output has now dipped below the target level allowed in the deal of 11.18 million bpd.

https://www.reuters.com/article/us-russia-oil-exports/russian-oil-quality-back-to-normal-at-baltic-port-after-contamination-idUSKCN1SJ10E

Equinor has acquired an additional 22.45% stake in the Caesar Tonga oilfield in the U.S. Gulf of Mexico from Shell for $965 million in cash, the Norwegian company said on Monday.

The acquisition will increase Equinor’s interest in the deepwater field, operated by Andarko, to 46% percent, giving it an additional 15,000 barrels of oil equivalents per day (boepd).

Its current net production from the field is 18,600 boepd, compared to Equinor’s total U.S. Gulf of Mexico production of 110,000 boepd in the first quarter.

“We are pleased to increase our presence in the United States, one of our core areas,” the head of Equinor’s offshore U.S. production, Christopher Golden, said in a statement.

“This is an asset we understand well, and our larger interest will deliver significant additional free cash flow from day one,” he added.

Later this year, Equinor will drill an exploration well at its Monument prospect, which could further increase the company’s foothold in the area, Golden added.

Andarko has a 33.7 percent interest in Caesar Tonga, while Chevron holds the remaining 20.25 percent.

https://www.reuters.com/article/us-equinor-shell-usa/equinor-buys-additional-stake-in-offshore-u-s-oilfield-for-965-million-idUSKCN1SJ18U

Only one Indian buyer of Iranian oil has taken up Saudi Arabia’s offer of additional oil to make up for the loss of supplies from Tehran due to U.S. sanctions, taking an extra 2 million barrels from the Kingdom for June shipment, industry sources said.

Last month, Saudi Arabia approached Indian buyers offering them additional supplies to compensate for loss of Iranian oil after the United States threatened to sanction entities buying oil from Tehran, the sources said.

The United States had imposed new sanctions on Iran in November last year, but gave a six-month waiver to eight countries, including India, which allowed them to import some Iranian oil.

India was able to buy about 300,000 barrels per day (bpd) of Iranian oil under the waiver. But last month, Washington ended the waivers and said buyers should stop Iranian oil purchases or face sanctions.

Only state refiners - Indian Oil Corp, Bharat Petroleum Corp, Mangalore Refinery and Petrochemicals and Hindustan Petroleum Corp - accounting for about 60 percent of India’s 5 million bpd refining capacity had purchased oil from Iran since November.

In January-April 2019 India received about 304,500 bpd Iranian oil.

In June, Saudi Arabia will supply an additional 250,000 tonnes (2 million barrels) of oil to Mangalore Refinery (MRPL) on top of its normal requirement of about 320,000 barrels (about 2.5 million barrels), one of the sources familiar with the matter said.

Another source said MRPL might not lift the additional Saudi oil as the refiner had declared force majeure and shut half of its plant due to water shortages.

Mangalore Refinery declined to comment. There was no immediate comment from IOC, HPCL, BPCL and Saudi Aramco.

“In our system, UAE and Iraq oil turned out to be better than Saudi oil,” a source at one of the Indian refineries said.

IOC, BPCL and HPCL have not placed a request for extra Saudi oil for June after the Kingdom raised official selling price for Asia, the sources said.

“Saudi OSPs for June have been very strong, so Indians may have taken extra from others at competitive rates,” said Sri Paravaikkarasu, director for Asia oil at Singapore-based consultancy FGE.

When Iran was under sanctions in 2012, Saudi Arabia and Iraq had raised market share in Asia. But since that time trade routes have shifted with new supplies, including from the United States, coming on to the markets.

“Saudi will have to fill some of the void left by Iran but it will not be a one to one replacement,” Paravaikkarasu said. “Indian refiners’ oil import policy is very flexible now and they are no longer relying on one or two particular producers.”

Indian refiners have raised optional volumes under annual contracts with key producers as well as testing new grades and origins to make up for loss of Iranian oil.

Also, U.S. crude’s widening discount to Brent has strengthened demand for U.S. crude exports.

“India wants to diversify away from Middle East because of lots of geopolitical issues relating to the region,” Paravaikkarasu said. “The Middle East will continue to be the mainstay for Indian refiners but they would like to tap new stable areas when it comes to requirement of incremental barrels.”

https://uk.reuters.com/article/uk-india-saudi-iran/only-1-indian-client-of-iran-takes-up-extra-saudi-oil-for-june-sources-idUKKCN1SJ19Y

U.S. oil output from seven major shale formations is expected to rise by about 83,000 barrels per day (bpd) in June to a fresh peak of about 8.49 million bpd, the U.S. Energy Information Administration said in its monthly drilling productivity report on Monday.

One of the largest changes is forecast in the Permian Basin of Texas and New Mexico, where output is expected to climb by 56,000 bpd to a new record of about 4.17 million bpd in June. That would be the biggest increase since February.

In North Dakota’s Bakken region, production is expected to jump by 16,000 bpd to a record of 1.42 million bpd while in the Eagle Ford, output is expected to slide by about 942 bpd to 1.43 million bpd.

A shale revolution and production increases particularly from the Permian basin and the Bakken have helped make the United States the biggest oil producer in the world, ahead of Saudi Arabia and Russia.

Major oil companies like Exxon Mobil Corp and Chevron Corp are boosting their presence in shale, particularly in the Permian, the largest U.S. shale oil field.

Separately, U.S. natural gas output was projected to increase to a record 80.7 billion cubic feet per day (bcfd) in June, the EIA said. That would be up 0.9 bcfd over the May forecast and mark a fifth consecutive monthly increase. A year ago in June, output was 68.2 bcfd.

The EIA projected gas output would increase in most of the big shale basins in June, except Anadarko in Oklahoma and Texas and Eagle Ford in Texas.

Output in the Appalachia region in Pennsylvania, Ohio and West Virginia, the nation’s biggest shale gas play, was set to rise almost 0.4 bcfd to a record 32.1 bcfd in June. Appalachia production was 27.5 bcfd in June a year ago.

The EIA said producers drilled 1,364 wells and completed 1,407, the most since January 2015, in the biggest shale basins in April, leaving total drilled but uncompleted wells down 43 at 8,390, according to data going back to December 2013.

That was the biggest decline in drilled but uncompleted wells since March 2018 when they fell by 104.

https://www.reuters.com/article/us-usa-oil-productivity/u-s-shale-output-to-hit-new-record-of-8-49-million-bpd-in-june-eia-idUSKCN1SJ21T

(Bloomberg) -- While the global crude market keeps showing

signs that stockpiles are getting tight, U.S. benchmark futures

are signaling plenty of supply. Contracts for July delivery of

Brent crude are trading at a premium of more than $3 a barrel

above December, doubling from a month ago, while the same spread

for West Texas Intermediate is at about 39 cents. The divergence

comes amid OPEC+ production cuts, and rising geopolitical

tensions from Venezuela to Iran, while surging Permian Basin

production swells inventories at the U.S. storage hub in

Cushing, Oklahoma.

To contact the reporter on this story:

Catherine Ngai in New York at cngai16@bloomberg.net

To contact the editors responsible for this story:

David Marino at dmarino4@bloomberg.net

Sophie Caronello

استكملت شركة سرت بنجاح أعمال الحفر التطويري للبئر (وو03-6) بطبقة القرقاف الغازية في حقل الاستقلال النفطي. وتجدر الإشارة إلى أنّ المؤسسة الوطنية للنفط تقوم بدعم أنشطة الحفر التطويري في قطاع النفط الليبي، وذلك في إطار حرصها على زيادة القدرة الانتاجية للحقول وضمان استمرار تزويد محطات توليد الكهرباء الساحلية باحتياجاتها من الغاز.

وقد تمّت عمليّة اختبار البئر يوم الأحد الموافق 12 مايو 2019، وقد تم حفر هذا البئر باستخدام تقنية سائل آفرون الحديثة للحفر وتحت إشراف شركة الجوف

وكانت النتائج الأولية للحفر مشجّعة:

قطر الخانق: 32/64 بوصة

معدل انتاج المكثفات : 263 برميل /ي

معدل انتاج الغاز : 7.103 م.ق.م/ي

قطر الخانق: 40/ 64 بوصة

معدل انتاج المكثفات: 328 برميل/ي

معدل انتاج الغاز : 11.725 م.ق.م/ي

قطر الخانق: 48/64 بوصة

معدل انتاج المكثفات : 455 برميل /ي

معدل انتاج الغاز : 13.979 م.ق.م/ي

هذا وسيتم استكمال البئر بواسطة أنابيب الإنتاج وملحقات البئر الخاصة والمصممة حسب ظروف المكمن المحدّدة.

وتجدر الإشارة إلى أنّ شركة سرت مسؤولة عن نظام نقل الغاز وأنابيب الغاز الساحلية الممتدّة من بنينة إلى مليته، والتي تنقل الغاز الطبيعي الذي يزوّد المنشآت الصناعية ومحطّات توليد الكهرباء ومحطات تحلية المياه.

http://bit.ly/2LI14tA

طرحت إيران حلولا لتفعيل آلية التعامل التجاري مع أوروبا، والتي تهدف إلى إنقاذ الاتفاق النووي من خلال السماح لطهران بمواصلة التعامل مع الشركات الأوروبية رغم العقوبات الأمريكية. وقال محافظ البنك المركزي الإيراني عبد الناصر همتي، إن أسهل طريقة لتفعيل الآليتين الأوروبية 'إينستكس' والإيرانية 'ساتما'، وهي شركة نظيرة للآلية الأوروبية، تتمثل بقيام الشركات الأوروبية باستيراد النفط من إيران أو منح خط ائتمان للمصدرين الأوروبيين لبدء التصدير إلى إيران.

وانتقد المسؤول الإيراني من خلال تدوينة على 'إنستغرام' نشرها مساء الاثنين تقاعس الجانب الأوروبي في تفعيل آلية التجارة، التي قدمت قبل 3 أشهر من قبل الدول الموقعة للاتفاق النووي وهي فرنسا وبريطانيا وألمانيا. وقال همتي إن 'حديث الأوروبيين عن سعيهم لتفعيل الآلية أصبح عبارة مكررة وبالية'، معتبرا أن الحل الذي قدمه هو الطريقة الأمثل لتفعيل هذه الآلية.

وأضاف: 'إذا كان الأوروبيون قلقين من رد فعل الولايات المتحدة إزاء السلع المصدرة إلى إيران فبإمكانهم اختبار قدرتهم على تصدير السلع الأساسية والأدوية. الآن يمكن القول إن الكرة في ملعب أوروبا'.

يذكر أن ألمانيا وفرنسا وبريطانيا أطلقت في نهاية يناير الماضي آلية 'إينستكس' لتسهيل الحركة المالية والتجارية مع إيران. وتتخوف الإدارة الأمريكية من تأثير هذه الآلية سلبا على العقوبات المفروضة على طهران، والتي تسعى من خلال الضغط على إيران وإجبارها على إعادة التفاوض حول برنامجها النووي.

thawra

http://www.tehrantelegram.com/story-z23411430

Iran has offered solutions to activate the mechanism of dealing with Europe, which aims to save the nuclear deal by allowing Tehran to continue to deal with European companies despite US sanctions. The easiest way to activate the European mechanisms 'Instex' and the Iranian 'Satma', a counterpart company of the European Mechanism, is the European companies to import oil from Iran or to give a line of credit to European exporters to start exporting to Iran.

He criticized the Iranian official through a post on the 'instagram' published on Monday evening, the failure of the European side to activate the trade mechanism, which was submitted three months ago by the signatories to the nuclear agreement, France, Britain and Germany. Hamati said that 'the Europeans' talk about their efforts to activate the mechanism has become a repetitive and obsolete', saying that the solution presented by is the best way to activate this mechanism.

"If Europeans are concerned about the US reaction to goods exported to Iran, they can test their ability to export commodities and medicines. Now it can be said that the ball is in the stadium of Europe '.

At the end of January, Germany, France and Britain launched the 'Instex' mechanism to facilitate financial and trade movement with Iran. The administration fears the impact of this mechanism negatively on the sanctions imposed on Tehran, which seeks through pressure on Iran and forced to renegotiate its nuclear progra

RIYADH/DUBAI (Reuters) - Saudi Arabia said armed drones struck two of its oil pumping stations on Tuesday, two days after the sabotage of oil tankers near the United Arab Emirates, and the U.S. military said it was braced for “possibly imminent threats to U.S. forces in Iraq” from Iran-backed forces.

The attacks took place against a backdrop of U.S.-Iranian tension following Washington’s decision this month to try to cut Iran’s oil exports to zero and to beef up its military presence in the Gulf in response to what it said were Iranian threats.

Tuesday’s attacks on the pumping stations more than 200 miles (320 km) west of Riyadh and Sunday’s on four tankers off Fujairah emirate have raised concerns that the United States and Iran might inching toward military conflict.

However, U.S. President Donald Trump denied a New York Times report that U.S. officials were discussing a military plan to send up to 120,000 troops to the Middle East to counter any attack or nuclear weapons acceleration by Iran.

“It’s fake news, OK? Now, would I do that? Absolutely. But we have not planned for that. Hopefully we’re not going to have to plan for that. And if we did that, we’d send a hell of a lot more troops than that,” Trump told reporters.

RELATED COVERAGE

• Saudi Arabia says 'terrorist attack' on oil tankers raises new security concerns
• Saudi Arabia says pipeline sabotage targets kingdom, global oil supply

See more stories

Iran’s Supreme Leader Ayatollah Ali Khamenei said there would not be war with the United States despite mounting tensions over Iranian nuclear capabilities, its missile program and its support for proxies in Yemen, Iraq, Syria and Lebanon.

“There won’t be any war. The Iranian nation has chosen the path of resistance,” he said in comments carried by Iran’s state TV. He repeated that Tehran would not negotiate with Washington over Iran’s 2015 nuclear deal with major powers.

The U.S. military cited possible imminent threats to its troops in Iraq and said they were now on high alert. The U.S. was responding to comments from a British deputy commander of the U.S.-led coalition fighting Islamic State remnants in Iraq and Syria who said there had been no increase in the threat from Iran-backed militia.

The comments “run counter to the identified credible threats available to intelligence from U.S. and allies regarding Iranian backed forces in the region,” said Navy Captain Bill Urban, a spokesman at the U.S. military’s Central Command.

Trump withdrew the United States from the Iran nuclear deal a year ago and has sharply increased economic sanctions on Iran.

Under the accord negotiated by Trump’s predecessor Barack Obama, Iran agreed to curb its uranium enrichment capacity, a potential pathway to a nuclear bomb, in return for sanctions relief.

Mexico signed a decree granting Pemex additional fiscal relief to boost oil output from mature fields, which are currently unprofitable under existing terms, the country's finance secretary said Monday.

Pemex will be able to extract up to an additional 400,000 b/d from these areas as a result of this new decree, Carlos Urzua said at a webcast event, in which the state-owned company closed a finance deal with a group of lenders.

The agreement with J.P. Morgan, HSBC, and Mizuho Securities will extend an existing $5.5 billion credit line to Pemex for an additional two years, and refinance $2.5 billion in debt. Under the deal, Pemex will pay an interest rate of 4.85%, much lower than the company's current international financing rates, the CEO of J.P. Morgan Mexico, Felipe Garcia Moreno, said at the event.

The tax relief will be enforced via the migration of certain mature fields from legacy assignment titles into production sharing contracts introduced by Mexico's 2014 energy reform, Urzua said.

Urzua did not say what areas will be migrated. However, he said these are mature fields, which are marginally operating as they are not profitable due to Pemex's current production sharing duties under legacy assignment titles, which cap capital deductions to 12.5% compared with 60% under E&P contracts.

"This will give Pemex a huge relief, allowing to restart some areas that weren't profitable under the old regime," he said.

This new decree will allow Pemex to credit $1.5 billion in 2019 alone, allowing it to boost its upstream investment, the company said in a statement Monday.

'MILKED THIS LITTLE COW'

Pemex's cash flow before taxes is reasonable compared with international peers, Urzua said. According to financial reports, Pemex had pre-tax income of $15.3 billion in 2018.

However, the company's production sharing duties with the federal government were $22.9 billion, resulting in a net loss of $7.5 billion for 2018.

"What is the problem? The problem is that for too long we have milked this little cow to avoid rising any other taxes or fighting fiscal evasion," Urzua said.

Pemex had a fiscal balance of $686 million in April, compared with a net loss of $3.2 billion in January, which it incurred as a result of tax payments, the CEO of Pemex, Octavio Romero Oropeza, said at the event.

Romero said that Pemex's debt is manageable, even though at $106 billion it is the largest for any oil company in the world. Pemex's debt in 2014 was $43 billion.

To offset Mexico's revenue loss from the fiscal relief, Mexico's government has grown tax collection rates by 5%, and expects to raise an additional $5.2 billion in 2019, said Mexican President Andres Manuel Lopez Obrador at the event .

According to the Organization of Economic Cooperation and Development (OECD), Mexico's tax collection as a share of its GDP is 17.4%, nearly half the rate of Brazil or Argentina.

https://www.spglobal.com/platts/en/market-insights/latest-news/oil/051319-mexicos-pemex-could-add-400000-b-d-of-production-with-new-fiscal-relief-decree-finance-secretary

The American Petroleum Institute reported late Tuesday that U.S. crude supplies rose by 8.6 million barrels for the week ended May 10, according to sources. The API also reportedly showed a stockpile increases of 567,000 barrels in gasoline and 2.2 million barrels in distillates.

Price Futures Group expected the API data to show a decline of 3 million barrels in crude supplies, according to analyst Daniel Flynn. It had also forecast stockpiles decreases of 2 million barrels each for gasoline and distillates.

Inventory data from the Energy Information Administration will be released Wednesday.

https://www.marketwatch.com/story/oil-prices-fall-as-api-data-reportedly-show-a-surprise-weekly-climb-in-us-crude-supply-2019-05-14

While the ongoing struggle for control over the Venezuelan state between embattled President Nicolas Maduro and National Assembly leader and interim President Juan Guaidó has captured the world’s attention in recent weeks, a more discreet—but arguably equally important—battle has been playing out in U.S. federal courts that will help determine control over key Venezuelan state assets, such as the U.S. subsidiaries and corporate holdings of state oil behemoth Petróleos de Venezuela, SA (PDVSA).

The Trump Administration’s January 2019 decision to recognize Mr. Guaidó as Venezuela’s lawful president was followed in February by U.S. Treasury Department Office of Foreign Assets Control (OFAC) measures to block PDVSA-related accounts under the Maduro government’s control and redirect those funds to the opposition. On February 13, 2019, the Guaidó-led National Assembly designated a new board of directors for PDVSA-owned U.S. subsidiary CITGO, followed by the designation on February 26, 2019 of attorney general José Ignacio Hernández, with a mandate to protect, control, and recover assets belonging to the republic outside Venezuela.

With billions at stake, one threshold in the opposition’s efforts to legitimize its mandate has been to determine whether U.S. courts will recognize legal counsel retained by Mr. Guaidó to represent the republic’s interests in ongoing disputes and litigation in the United States. Two cases currently working their way through U.S. federal courts may be good harbingers of who will control Venezuela’s state-owned assets (and liabilities) moving forward.

The first, Rusoro Mining Limited, Gold Fields Limited v. Bolivarian Republic of Venezuela is being heard by the U.S. Court of Appeals for the District of Columbia and involves a $1.2 billion arbitration award issued in 2016. The case stems from Venezuela’s failure to compensate Canadian gold-mining firm Rusoro for seizing its assets without compensation in a 2011 drive to nationalize extractive industries. In a May 1, 2019 ruling on a motion filed by attorneys representing the Maduro government that alleged that legal counsel to Mr. Guaidó have no standing to litigate the case, the court denied the Maduro motion, and argued that the executive branch’s “action in recognizing a foreign government…is conclusive on all domestic courts, which are bound to accept that determination.” The judges’ ruling further stated that, “it has long been established that only governments recognized by the United States...are entitled to access to our courts…“).

In a separate similar case, third circuit U.S. court of appeals judge Thomas Ambro ruled on March 20 that Mr. Guaidó’s representatives have standing to present arguments in a legal dispute with Canadian mining firm Crystallex International Corp stemming from the 2011 nationalization of Las Cristinas, a Crystallex-controlled mining project. In his ruling, judge Ambro wrote, “We grant the Republic of Venezuela’s motion to intervene,” in its request for a 120-day stay to allow the national assembly’s counsel “sufficient time to evaluate its position in this and other cases.”

https://www.jdsupra.com/legalnews/struggle-for-control-over-venezuelan-47644/&ct=ga&cd=CAIyGjUwYWY4ZjhiMTRiNmY5OWU6Y29tOmVuOkdC&usg=AFQjCNGhlk33VpiXatDZfg_qiTaA1go6m

Saudi Aramco restarted pumping oil on Wednesday through the pipeline which was hit by drone attacks on Tuesday, Arab media report.

Two pumping stations along Aramco’s East-West oil pipeline in Saudi Arabia were attacked by explosive-laden drones in the early morning local time on Tuesday, the official Saudi Press Agency (SPA) reported yesterday, citing Saudi Energy Minister Khalid al-Falih, who described the attack as one of “terrorism and sabotage.”

The drones laden with explosives targeted the pump stations on the pipeline which carries oil from eastern Saudi Arabia to the Yanbu port.

Saudi Aramco issued a statement on Tuesday, saying that the sabotage caused minor damage and a fire at one of the pumping stations. Aramco temporarily shut down the pipeline yesterday as a precautionary measure and noted that no injuries or fatalities were reported. The company’s oil and gas supplies haven’t been impacted as a result of the incident either, it said.

“Mr. Al-Falih confirmed that the Kingdom of Saudi Arabia condemns this cowardly attack, emphasizing that this act of terrorism and sabotage in addition to recent acts in the Arabian Gulf do not only target the Kingdom but also the security of world oil supplies and the global economy. These attacks prove again that it is important for us to face terrorist entities, including the Houthi militias in Yemen that are backed by Iran,” the official Saudi agency said on Tuesday.

Related: The Battle For Control Over Iraq’s Oil

This statement came out hours after Houthi-owned TV Almasirah reported that “7 Drones have targeted vital Saudi facilities.”

Reports of the drone attack on Saudi Aramco’s oil infrastructure came a day after Saudi Arabia said that two of its oil tankers were attacked by saboteurs near the United Arab Emirates (UAE), while the UAE said that a total four vessels were attacked off its coast at the port of Fujairah.

The heightened security concerns and the potential threat to global oil supplies in the Middle East lifted oil prices on Monday and early Tuesday, outweighing concerns about an escalating U.S.-China trade war and slowing global economic growth. A large crude build reported by API later on Tuesday, however, weighed down on oil prices, which were still down just before the EIA’s inventory report release on Wednesday.

By Tsvetana Paraskova for Oilprice.com

More Top Reads From Oilprice.com:

https://oilprice.com/Latest-Energy-News/World-News/Saudi-Aramco-Restarts-Oil-Pipeline-After-Drone-Attack.html&ct=ga&cd=CAIyHGMzMDI4NGM4N2E3MjhhZTM6Y28udWs6ZW46R0I&usg=AFQjCNHTbosnQTeoxVGBfUdvnaITZVVnH

Performance Levels

Looking performance record on shares of SandRidge Energy (SD) we observed that the stock has seen a move -36.78% over the last 52-week trading period. The stock generated performance of 9.69% tracking last 3 months and -16.76% over the recent 6 months. Investors will be anxiously watching to see if things will turn around and the stock will start gaining or losing momentum over the next few months. If we look back year-to-date, the stock has performed 17.48%. Shares are at 7.45% over the previous week and 6.56% over the past month.

Investors tracking shares of SandRidge Energy (SD) may be focusing on where the stock is trading relative to its 52-week high and low. At the time of writing, the stock had recently reached at $8.94. At this price, shares can be seen trading -51.07% off of the 52-week high mark and 28.14% away from the 52-week low. Investors often pay increased attention to a stock when it is nearing either mark. The Price Range 52 Weeks is one of the tools that investors use to determine the lowest and highest price at which a stock has traded in the previous 52 weeks. It has a market cap of $315.78M.

Volume Evaluation

Active moving action has been spotted in SandRidge Energy (SD) on Tuesday as stock is moving on change of 6.18% from the open. The US listed company saw a recent price trade of $8.94 and 732315 shares have traded hands in the session. There are 337.65K shares which are traded as an average over the last three months period.

Trading volume can help an investor identify momentum in a stock and confirm a trend. If trading volume increases, prices generally move in the same direction. That is, if a security is continuing higher in an uptrend, the volume of the security should also increase and vice versa. Trading volume can also signal when an investor should take profits and sell a security due to low activity. If there is no relationship between the trading volume and the price of a security, this signals weakness in the current trend and a possible reversal.

Analyst Views: Fluctuating the focus to what the Wall Street analysts are projecting, we can see that the current consensus target price on shares is $10. Analysts often put in a lot of work to study stocks that they cover.

Volatility Insights

Watching some historical volatility numbers on shares of SandRidge Energy (SD) we can see that the 30 days volatility is presently 3.68%. The 7 days volatility is 4.77%. Following volatility data can help measure how much the stock price has fluctuated over the specified time period. Although past volatility action may help project future stock volatility, it may also be vastly different when taking into account other factors that may be driving price action during the measured time period.

The Average True Range (ATR) value reported at 0.32. The average true range (ATR) is a technical analysis indicator that measures volatility by decomposing the entire range of an asset price for that period. A stock experiencing a high level of volatility has a higher ATR, and a low volatility stock has a lower ATR. The ATR may be used by market technicians to enter and exit trades, and it is a useful tool to add to a trading system. It was created to allow traders to more accurately measure the daily volatility of an asset by using simple calculations. The indicator does not indicate the price direction; rather it is used primarily to measure volatility caused by gaps and limit up or down moves. The ATR is fairly simple to calculate and only needs historical price data.

Technical Considerations

SandRidge Energy (SD) stock positioned -11.71% distance from the 200-day MA and stock price situated 9.71% away from the 50-day MA while located 6.99% off of the 20-day MA. SandRidge Energy (SD) traded moved 0.45% from the 50-day high price and spotted a change of 26.81% from the 50-day low point.

RSI value sited with reading of 64.88. RSI is one of the most popular and widely used technical indicators that provides us with many ways to generate buy and sell signals. The fact that RSI is a bounded oscillator (it takes on values from 0 to 100) allows us to identify overbought and oversold levels quite easily. Wilder considered RSI values over 70 overbought and values below 30 oversold, but these values can be adjusted to suit particular needs and markets. For instance, 80 could be used as overbought line in a strong uptrend and 20 as oversold line in a strong downtrend.

https://newsleading.info/2019/05/15/where-sandridge-energy-sd-stock-is-moving-now-spotted-at-8-94/&ct=ga&cd=CAIyGmQ5ODUxZThlNzdjOWFkZDM6Y29tOmVuOkdC&usg=AFQjCNHbdJMBJtMxO1DatktkkceMW7GqL

Exports of the Permian Basin’s newest kind of oil are set to jump as production surges, exceeding the appetite of U.S. refiners.

Sales of the new grade, known as West Texas Light, began in September, as explorers sought to separate out increasingly lighter and less sulfurous crude bubbling up from wells in West Texas and New Mexico, so it wouldn’t lessen the quality of U.S. benchmark West Texas Intermediate. WTL supply has grown to over 500,000 barrels a day, a nearly four-fold rise from last year.

While some of that is staying close by, most will need to be exported. Even as ample shale barrels and tighter supplies of heavier crudes have encouraged U.S. refiners to process the lightest oil since 1990, that may reach a limit soon. But since many of the biggest refineries have invested billions of dollars in upgrades over the years and are set up to run the heaviest, dirtiest oil, there’s only a certain amount of light oil they can handle.

“I suspect that refineries that can blend to run lighter slates are likely already doing so to the best they can,” said Michael Tran, a commodity strategist at RBC Capital Markets LLC in New York. “Every incremental barrel produced in the U.S. should be earmarked for export,” unless it’s a heavy crude, Tran said.

Shipments overseas began in February and have neared 1.42 million barrels through this month. Most was sent to the Netherlands and the rest for Canada, while none has headed to Asia so far, according to U.S. Customs data and ship tracking data compiled by Bloomberg.

Renewed U.S.-led sanctions on Iran could provide an opportunity. Buyers of Iranian condensates such as South Korea, might consider WTL, Jonathan Aronson, analyst for Cornerstone Marcro LLC in New York.

Presently, some 1 million barrels of storage has been set aside in the Permian and Cushing, Oklahoma, to market WTL, according to people familiar with the matter. Some pipes are starting to accept it as a proper grade, the people said.

More Pipelines

Still, more pipeline capacity would be needed, which is expected to start coming online late this year and in 2020. “Pipelines from Midland and Cushing to the Gulf Coast are full right now. It’s a problem for any crude, including WTL,” Aronson said.

WTL is being marketed to Asian buyers for refining and petrochemical use, according to a report by analysts at Macquarie Capital (USA) Inc. Even with its higher content of light products such as naphtha, it would be globally marketable for at least three years. However, that could change later on because of rapidly growing natural gas liquids and condensates supply, both of which have similar yields.

That might be a boon for buyers, as WTL prices could drop, particularly in Asia, which has numerous other options for light, low-sulfur crudes. Currently, the grade is trading at $1 to $1.50 a barrel under WTI Midland, compared with a $2.50 discount last month, according to people familiar with the matter.

On the whole, WTL would be a great crude for a simple refinery to run and chemical plants would like it, whether in Asia or Europe, Cornerstone’s Aronson said.

https://www.oilandgas360.com/surge-of-new-permian-basin-oil-to-feed-global-supply/

The bills are due for millions of barrels of contaminated Russian oil that have been stuck for weeks in pipelines from Belarus to Germany - but no one wants to pay.

Western oil companies and European refiners that bought the oil a month ago, before discovering it was unusable, have so far refrained from freezing payments as they are keen to maintain good long-term relations with the world’s second biggest oil exporter and avoid protracted legal battles in Russian courts.

Instead, several Western buyers have asked Russian producers if they can postpone payments for the tainted crude while buyers and sellers agree how to resolve the mess - and how to share the costs, four traders involved in Russian oil trading said.

For the buyers of an estimated 19 million barrels of contaminated crude stuck in the pipeline and loaded on tankers, it’s a $1.2 billion question.

The buyers want Russian producers to give guarantees in the form of bank deposits that they will contribute to the clean-up, or delay payments due this week until the crisis is resolved, said a source at European refiner, who declined to be named.

“There’s around 0.8-0.9 million tonnes of dirty oil sitting in the pipelines between Belarus and Germany that no refiner wants to take,” he said. “This oil needs to be evacuated somewhere to restart the pipeline. But it would be wrong for Russia to assume European refiners will bear all costs.”

The refiner said Russian oil producers had yet to respond to the proposals made by major European buyers.

“We are ready to help sort out the problem and find solutions for the dirty oil. But we want Russian producers to come up with financial guarantees that they will help cover the costs,” said a second buyer of Russian oil in Europe.

Russian state-owned oil producer Rosneft said it was too early to comment on the issue. Lukoil declined to comment and Surgutneftegas said it was holding normal commercial talks with its buyers.

International oil companies and trading houses have not commented publicly on the contamination crisis.

State Russian pipeline monopoly Transneft declined to comment on the issue of compensation. It said on Tuesday it was not to blame for the organic chloride contamination because it could only have been added by producers.

MAY DEADLINES

It has been three weeks since Belarus told oil refiners and pipeline operators in Europe that the crude heading towards them down the 5,500 km (3,400 mile) Druzhba pipeline network was heavily contaminated with organic chloride.

Russian oil flows via Druzhba were halted, sending crude to a six-month high above $75 a barrel and tarnishing Russia’s reputation as an exporter at a time of rising competition with U.S. and Middle Eastern oil sales.

Russia has since said the oil was contaminated deliberately by an unnamed local producer while Belarus said it would take months to restore clean oil supplies to Europe via Druzhba.

Organic chloride is used to clean oil wells and accelerate the flow of crude but it should be removed before the oil enters the supply chain as the compounds can damage refining equipment.

To get the pipeline working again, the tainted oil needs to be removed and stored somewhere so it can be diluted with clean oil - in some cases in proportions of one to 30 - to bring the organic chloride down to safe levels.

Traders estimate the process for all the contaminated oil in Druzhba would cost tens of millions of dollars.

In the meantime, the question of who should pay for the contaminated oil when the bills come due this week remains.

$1.2 BILLION QUESTION

Exports to Europe via Druzhba are fairly complicated because they involve dozens of sellers, buyers and banks. Normally, contracts are rolled over and letters of credit renewed as payments are made via intermediaries - and the oil keeps flowing.

But the contamination has thrown a spanner in the works.

Russian producers sell oil to European refiners along the Druzhba pipeline in Germany, Poland, Slovakia, Hungary and the Czech Republic. Those refineries are owned by companies such as PKN Orlen, Grupa Lotos, MOL, Total, Eni and Shell, among others.

Once the Russian oil producers have transferred their crude to Transneft, it effectively becomes responsible for delivering the right quality of crude to pipeline companies in Europe.

As soon as those companies, such as Poland’s PERN or Slovakia’s Transpetrol, acknowledge receipt of oil from Transneft, the ownership of the crude passes from Russian sellers to European buyers.

But no money changes hands at this point as payment is usually due in the middle of the next month, meaning the bills for oil exported via Druzhba in April should be paid by mid-May.

According to trading sources, at least 19 million barrels of contaminated crude, worth $1.2 billion at current market prices, has yet to be paid for.

That includes 8 million barrels in the Druzhba pipeline and another 11 million barrels loaded onto tankers at Ust-Luga port in the Baltic. Those vessels are now anchored off Europe because the trading houses that took on the oil are struggling to sell it to refiners.

Russian producers, meanwhile, have already paid taxes to the Russian state for the oil they sold in April - such as export duties and mineral extraction taxes - putting them under pressure to recoup money owed by the buyers.

‘EXPENSIVE EXERCISE’

With payment deadlines looming, none of the Western oil buyers has yet instructed their banks to withhold funds as that could have significant repercussions, according to traders.

“You can of course say that I won’t pay because I didn’t get the right quality oil,” said an executive at a major commodities trading house. “But no one wants this nuclear option. We prefer responsible dialogue.”

Another source with a major buyer said the money it owes for Ust-Luga cargoes will be paid on time but it will be accompanied by claims for damages against the sellers for poor quality.

Further complicating talks between buyers and sellers is the fact that the various oil contracts in question fall under different legal systems.

Most sales along the pipeline are governed by Russian law - which leaves issues of oil quality open to interpretation. Sales from Ust-Luga, meanwhile, are mostly governed by English law, according to traders familiar with the contracts.

“We expect a complicated claim handling through the whole supply chain of Russian crude oil,” said Swedish refiner Preem.

Belarusian refiner Naftan said it had filed claims against unnamed Russian suppliers for delivering low quality oil during April.

For now though, until buyers and sellers can agree how to get the tainted oil out of Druzhba - and who will foot the bill - the pipeline is set to remain shut.

“Based on Druzhba’s normal throughput, every new day of stoppage costs Russia $80 million in lost revenue. That is an expensive exercise,” said the trader with a European refiner.

https://www.reuters.com/article/us-russia-oil-insight/in-limbo-the-dirty-russian-oil-no-one-wants-to-pay-for-idUSKCN1SL1JG

U.S. crude oil refinery inputs averaged 16.7 million barrels per day during the week ending May 10, 2019, which was 271,000 barrels per day more than the previous week’s average. Refineries operated at 90.5% of their operable capacity last week. Gasoline production decreased last week, averaging 9.9 million barrels per day. Distillate fuel production increased last week, averaging 5.3 million barrels per day.

U.S. crude oil imports averaged 7.6 million barrels per day last week, up by 919,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 7.2 million barrels per day, 9.6% less than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 752,000 barrels per day, and distillate fuel imports averaged 41,000 barrels per day.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 5.4 million barrels from the previous week. At 472.0 million barrels, U.S. crude oil inventories are about 2% above the five year average for this time of year. Total motor gasoline inventories decreased by 1.1 million barrels last week and are about 2% below the five year average for this time of year. Finished gasoline inventories increased while blending components inventories decreased last week. Distillate fuel inventories increased by 0.1 million barrels last week and are about 4% below the five year average for this time of year. Propane/propylene inventories increased by 2.8 million barrels last week and are about 19% above the five year average for this time of year. Total commercial petroleum inventories increased last week by 14.6 million barrels last week.

Total products supplied over the last four-week period averaged 20.1 million barrels per day, up by 0.3% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.4 million barrels per day, up by 0.5% from the same period last year. Distillate fuel product supplied averaged 4.0 million barrels per day over the past four weeks, down by 4.5% from the same period last year. Jet fuel product supplied was up 11.0% compared with the same four-week period last year.

Domestic production down 100,000 bbls day

Exports up 1,025,000 bbls day

Cushing up 1.8 mln bbls

https://www.eia.gov/petroleum/supply/weekly/

https://www.ft.com/content/d3d63bba-7653-11e9-be7d-6d846537acab

 7 HOURS AGO When Vicki Hollub stood up to speak at Occidental Petroleum’s annual meeting last Friday, she knew she was facing a sceptical audience. After three years as chief executive, she had just agreed the most ambitious move of her career, the $56bn acquisition of rival Anadarko Petroleum, and many investors feared she was overreaching. Buying Anadarko, one of the largest US independent oil and gas groups, with assets around the world from Texas to Mozambique, will double the size of Occidental. It will also saddle the company with debts of around $50bn, in return for a business that has been failing to cover its capital spending from its operating cash flows. Ms Hollub promised billions of dollars worth of cost savings and productivity gains from the deal, but many investors remain sceptical that she can deliver. “It is simply outrageous,” said one top 10 shareholder before the meeting. The deal poses several operational risks as well as putting enormous pressure on Occidental’s balance sheet, he warned. Investors’ lack of enthusiasm for the deal was reflected in Occidental’s share price, which dropped to a 10-year low as Anadarko accepted its offer.

Occidental's Big Mistake: Overpaying For Resources In An Age Of Energy Abundance

May 16, 2019 6:54 AM ET|2 comments  | About: Occidental Petroleum Corporation (OXY), Includes: APC, BRK, COP, CVX, EOG, PSX, PXD, TOT, XOMMichael FitzsimmonsRenewable energy, oil & gas, dividend investing, gold

Summary

OXY's stock has been on a downward trend ever since it started bidding for Anadarko and is now trading at 12-year lows.

The company significantly overpaid for Anadarko's resource base, very similar to Exxon's deal for XTO.

Making matters worse was the "Buffett deal": great for Berkshire, but awful for OXY shareholders.

Meantime, Chevron walks away a stronger company with its financial discipline firmly intact (and a $1 billion break-up fee that will be used to buy back shares).

Occidental Petroleum's (OXY) stock has been heading lower ever since it started bidding for Anadarko Petroleum (APC). It's now trading at the same level it was back in May of 2007. Interestingly enough, so is Exxon Mobil(XOM). And for the same reason: overpaying for resources in an age of energy abundance (in Exxon's case, it was a $40 billion deal to buy XTO).

OXY should have realized that in an age of "no moat" energy investing (see my article Energy Companies' Big Problem? There's No Moat), it is a huge mistake to overpay for resources. As I pointed out in my "no moat" piece - instead of a handful of big companies dominating domestic energy production prior to the shale renaissance, there are now dozens and dozens of domestic E&P companies that are producing significant volumes of oil and gas.

Source: Yahoo Finance

The result, of course, is lower prices. NYMEX gas is currently trading around $2.60 and the CME futures strip show it will trade under $3 as far as the eye can see. Associated gas in the Permian Basin is so high, and pipeline exit capacity so constrained, that ConocoPhillips (COP) reported on its Q1 conference call that WAHA gas went severely negative during the quarter:

We're generally, I'd say in the first quarter of most of our gas was sold into Arizona and California market. So we didn't see why I type pricing. On the other hand – other side of that on the gas marketing side, we did benefit a good bit from Waha pricing as we were in the market some days with producers paying us, as much as $6 or $7 Mcf.

That is, Permian producers were paying COP $6-7/Mcf to take their gas production and ship it out of the region. Note that Conoco - which has a large gas marketing business and sells much of its regional gas production into Arizona and California - is not much exposed to WAHA pricing. That is one reason COP's average realized price for Q1 ($50.59/boe) was so much higher as compared to companies like EOG Resources (EOG) ($39.56/boe) and Pioneer Natural Resources (PXD) ($37.84/boe). The other, of course, is that COP's production profile is 75% levered to Brent instead of WTI.

Going forward, things aren't a whole lot better on the oil front. Domestic E&P companies are fully aware the oil price recovery they are currently enjoying is because both Saudi Arabia and Russia decided to cut back production in order to get the price up and to allow U.S. exports to elbow their way into the global oil market.

But even that may not work much longer because in the 2H of this year multiple Permian-to-Gulf Coast oil pipelines will go in-service - including Phillips 66's (PSX) 900,000 bpd Gray Oak pipeline - that will greatly enhance pipeline exit capacity out of the play. This is happening just as two heavyweights - Chevron (CVX) and Exxon - are now in "manufacturing mode" in the Permian and will be significantly ramping up production. Will Russia and Saudi Arabia continue to allow the US to pick up more global market share? Again, there is an abundance of supply.

Overpaying For Resources: A Recipe For Disaster

So as we have seen over the past few years, the price of natural gas has been decimated and the price of oil is dependent on the actions of other nation states to cut production. This is exactly what you would expect in an age of energy abundance and the "no moat" energy sector that enables any company with easy access to money and shale drilling technology can punch a hole, drill a well, and produce hydrocarbons.

The worst mistake a company can make in this environment is to overpay for resources. And OXY had a perfect example to learn from the Exxon deal for XTO. After years of spending tens of billion dollars on share buybacks, most of those shares were reissued in Exxon's $40 billion deal to buy XTO. And then the bottom dropped out of the price of gas. The XTO assets were not even able to pay the dividend obligation on the re-issued XOM shares. As a result, Exxon's stock today trades below where it was 10 years ago.

Similarly, OXY's stock is now trading below where it was 12 years ago. Why do I say OXY overpaid? Rather than go into an in-depth analysis of APC's reserves report (which many might argue is absolutely necessary), just consider that APC came to an agreement to sell out to Chevron for $33 billion. Now one would assume that Anadarko's CEO and Board of Directors did do an in-depth analysis of the reserves report. Some may disagree considering Anadarko's BOD decided to greatly increase the CEO's compensation should a buyout happen, and they may have a good point. But that's a separate issue and, still, the agreed upon price was $33 billion.

Then OXY comes along and bids ~$38 billion for Anadarko (~15% more than Chevron). If you tack on the $1 billion break-up fee that APC has to pay Chevron (and that OXY can't keep...), the bid was ~18% higher than Chevron's.

Even worse, OXY - in a hurry to get financing in place - made a $10 billion dealwhereby Buffett's Berkshire Hathaway (NYSE:BRK.A) (NYSE:BRK.B) will:

• Receive 100,000 shares of Cumulative Perpetual Preferred Stock with a liquidation value of $100,000 per share.
• Receive a warrant to purchase up to 80.0 million shares of Occidental common stock at an exercise price of $62.50 per share.
• Receive an 8% annual dividend on the preferred stock (or with respect to dividends that are accrued and unpaid, 9%).

So not only did OXY pay significantly more than Chevron was willing to pay (and that APC was willing to take), they took on some very expensive debt AND created what is in effect a new and separate class of stock just for Berkshire Hathaway. Wow.

Now, some analysts made a big deal out of the fact that OXY was able to make an $8.8 billion deal to sell APC's African assets to Total (TOT). That will certainly help OXY's balance sheet. However, consider that Chevron has much more experience in building and operating LNG assets than either OXY or APC and likely had a very good idea of what APC's African assets were worth - whether by monetizing the asset by selling it, or, by participating in the LNG project itself.

Summary And Conclusion

As a result of the big Anadarko deal, OXY's stock is weakening and Chevron's stock strengthening. Those who say Chevron "lost" in the deal obviously don't understand that Chevron - with a market cap of $232 billion, more than 5x that of OXY - could have easily "won" the bidding war for APC had it chose to do so. But, as Chevron CEO Michael Wirth said in the "bowing out" press release:

Winning in any environment doesn’t mean winning at any cost. Cost and capital discipline always matter, and we will not dilute our returns or erode value for our shareholders for the sake of doing a deal.

This quote echoed comments that ConocoPhillips CEO Ryan Lance made at this week's Annual Meeting regarding Permian M&A:

The big corporate M&A that requires these very large premiums that we've seen here in the last month or so, those are very tough. Those are hard to do. Those are destructive to value. They're destructive to returns.

It's no coincidence that I own both Chevron and Conoco. Both are FCF-generating machines with WTI over $60. Both have excellent management teams that are pragmatic about the new age of energy abundance and are showing excellent capital discipline. And both will likely significantly outperform those companies that are not pragmatic about the age of energy abundance and are not disciplined (Exxon and OXY, just to name two).

Chevron is a BUY and I reiterate my $135 price target based on expectations for high quality earnings and massive FCF generation (not to mention the extra $1 billion in share buybacks due to the break-up fee). See my late 2018 Seeking Alpha article Chevron: A FCF Generating Machine In High Gear. Chevron's 4% dividend yield is very attractive considering the recent US/China trade "squabble" has the 10-year Treasury back under 2.5%.

Note that Chevron is now a "conviction buy" at Goldman Sachs with a $144 price target.

TEHRAN, May 13 (MNA) – Oil futures rose on Monday on increasing concerns about supply disruptions in the crucial producing region of the Middle East after two oil tankers were attacked in the Sea of Oman.

Brent crude futures reached $71.71 a barrel at noon, up $1.09, Reuter reported.

US West Texas Intermediate (WTI) futures were at $62.45 per barrel, up 79 cents.

The United Arab Emirates said on Sunday that four commercial vessels were attacked near Fujairah, one of the world’s largest bunkering hubs. The port lies near the Strait of Hormuz, one of the world’s most important oil export waterways.

Saudi Arabia said on Monday that two Saudi oil tankers were among vessels targeted by the attack off the coast UAE coast.

Several Persian Gulf states have expressed concerns over the attack, condemning it as an attempt to undermine the security of the region. Iran’s Foreign Ministry called the incidents “worrisome and dreadful” and asked for an investigation into the matter.

Saudi Arabia and the UAE are the largest and third-largest producers, respectively, in the Organization of the Petroleum Exporting Countries (OPEC), according to the latest survey by Reuters.

Besides, according to analysts, the rising geopolitical tensions in the Middle East, together with sharply declining oil supplies from Venezuela and Iran due to the US' unilateral sanctions, will remain bullish for prices.

Investors are now focused on tightened supplies following OPEC-led production cuts since the start of the year.

Mehrnews

http://www.tehrantelegram.com/story-z23409204

Last Updated: July 25, 2017 (Notes)

full report

Overview

World chokepoints for maritime transit of oil are a critical part of global energy security. About 61% of the world's petroleum and other liquids production moved on maritime routes in 2015. The Strait of Hormuz and the Strait of Malacca are the world's most important strategic chokepoints by volume of oil transit.

The U.S. Energy Information Administration (EIA) defines world oil chokepoints as narrow channels along widely used global sea routes, some so narrow that restrictions are placed on the size of the vessel that can navigate through them. Chokepoints are a critical part of global energy security because of the high volume of petroleum and other liquids transported through their narrow straits. In 2015, total world petroleum and other liquids supply was about 96.7 million barrels per day (b/d).1 EIA estimates that about 61% that amount (58.9 million b/d) traveled via seaborne trade.2 Oil tankers accounted for almost 28% of the world’s shipping by deadweight tonnage in 2016, according to data from the United Nations Conference on Trade and Development (UNCTAD), having fallen steadily from 50% in 1980.3 International energy markets depend on reliable transport routes. Blocking a chokepoint, even temporarily, can lead to substantial increases in total energy costs and world energy prices. Chokepoints also leave oil tankers vulnerable to theft from pirates, terrorist attacks, political unrest in the form of wars or hostilities, and shipping accidents that can lead to disastrous oil spills. The seven chokepoints highlighted in this report are part of major trade routes for global seaborne oil transportation. Disruptions to these routes could affect oil prices and add thousands of miles of transit in alternative routes. By volume of oil transit, the Strait of Hormuz, leading out of the Persian Gulf, and the Strait of Malacca (linking the Indian and Pacific Oceans) are the world's most important strategic chokepoints. This report also discusses the role of the Cape of Good Hope, which is not a chokepoint but is a major trade route and potential alternate route to certain chokepoints.

Figure 1. Daily transit volumes through world maritime oil chokepoints All estimates in million barrels per day. Includes crude oil and petroleum liquids. Based on 2016 data.

Source: U.S. Energy Information Administration

Table 1. Volume of crude oil and petroleum products transported through world chokepoints and the Cape of Good Hope, 2011-16 (million b/d) Location 2011 2012 2013 2014 2015 2016 Strait of Hormuz 17.0 16.8 16.6 16.9 17.0 18.5 Strait of Malacca 14.5 15.1 15.4 15.5 15.5 16.0 Suez Canal and SUMED Pipeline 3.8 4.5 4.6 5.2 5.4 5.5 Bab el-Mandab 3.3 3.6 3.8 4.3 4.7 4.8 Danish Straits 3.0 3.3 3.1 3.0 3.2 3.2 Turkish Straits 2.9 2.7 2.6 2.6 2.4 2.4 Panama Canal 0.8 0.8 0.8 0.9 1.0 0.9 Cape of Good Hope 4.7 5.4 5.1 4.9 5.1 5.8 World maritime oil trade 55.5 56.4 56.5 56.4 58.9 n/a World total petroleum and other liquids supply 88.8 90.8 91.3 93.8 96.7 97.2 Note: Data for Panama Canal are by fiscal year.

Sources: U.S. Energy Information Administration analysis based on Lloyd's List Intelligence, Panama Canal Authority, Argus FSU, Suez Canal Authority, GTT, BP Statistical Review of World Energy, IHS Waterborne, Oil and Gas Journal, and UNCTAD, using EIA conversion factors.4

Oil tanker sizes

Ships carrying crude oil and petroleum products are limited by size restrictions imposed by maritime oil chokepoints. The global crude oil and refined product tanker fleet uses a classification system to standardize contract terms, to establish shipping costs, and to classify vessels for chartering contracts. This system, known as the Average Freight Rate Assessment (AFRA) system, was established by Royal Dutch Shell six decades ago, and the London Tanker Brokers' Panel (LTBP), an independent group of shipping brokers, oversees the system. AFRA uses a scale that classifies tanker vessels according to deadweight tons—a measure of a ship's capacity to carry cargo. The approximate capacity of a ship in barrels is determined using an estimated 90% of a ship's deadweight tonnage, which is multiplied by a barrel-per-metric-ton conversion factor specific to each type of petroleum product and crude oil, as liquid fuel densities vary by type and grade. The smaller vessels on the AFRA scale—the General Purpose (GP) and Medium Range (MR) tankers—are commonly used to transport cargos of refined petroleum products over relatively shorter distances, such as from Europe to the U.S. East Coast. Their smaller size allows them to access most ports around the globe. A GP tanker can carry between 70,000 barrels and 190,000 barrels of motor gasoline (3.2-8 million gallons), and an MR tanker can carry between 190,000 barrels and 345,000 barrels of motor gasoline (8-14.5 million gallons). Long Range (LR) class ships are the most common ships in the global tanker fleet, as they are used to carry both refined products and crude oil. These ships can access most large ports that ship crude oil and petroleum products. An LR1 tanker can carry between 345,000 barrels and 615,000 barrels of gasoline (14.5-25.8 million gallons) or between 310,000 barrels and 550,000 barrels of light sweet crude oil. A large portion of the global tanker fleet is classified as AFRAMAX. AFRAMAX vessels are ships between 80,000 deadweight tons and 120,000 deadweight tons. This ship size is popular with oil companies for logistical purposes, and many ships have been built within these specifications. Because the AFRAMAX range exists somewhere between the LR1 and LR2 AFRA scales, the LTBP does not publish a freight assessment specifically for AFRAMAX vessels. Over the history of AFRA, vessels grew in size, and newer classifications were added. The Very Large Crude Carrier (VLCC) and Ultra-Large Crude Carrier (ULCC) were added as the global oil trade expanded and larger vessels provided better economics for crude oil shipments. VLCCs are responsible for most crude oil shipments around the globe, including in the North Sea, home of the crude oil price benchmark Brent. A VLCC can carry between 1.9 million and 2.2 million barrels of a West Texas Intermediate (WTI) type crude oil.

Figure 2. Average Freight Rate Assessment (AFRA) Scale-Fixed Source: U.S. Energy Information Administration, London Tanker Brokers' Panel5

Note: AFRAMAX is not an official vessel classification on the AFRA scale but is shown here for comparison.

Strait of Hormuz

The Strait of Hormuz is the world's most important chokepoint, with an oil flow of 17 million b/d in 2015, about 30% of all seaborne-traded crude oil and other liquids during the year. In 2016, total flows through the Strait of Hormuz increased to a record high of 18.5 million b/d.

Located between Oman and Iran, the Strait of Hormuz connects the Persian Gulf with the Gulf of Oman and the Arabian Sea. The Strait of Hormuz is the world's most important oil chokepoint because its daily oil flow of about 17 million barrels per day in 2015, accounted for 30% of all seaborne-traded crude oil and other liquids. The volume that traveled through this vital choke point increased to 18.5 million b/d in 2016. EIA estimates that about 80% of the crude oil that moved through this chokepoint went to Asian markets, based on data from Lloyd’s List Intelligence tanker tracking service.6 China, Japan, India, South Korea, and Singapore are the largest destinations for oil moving through the Strait of Hormuz. Qatar exported about 3.7 trillion cubic feet per year of liquefied natural gas (LNG) through the Strait of Hormuz in 2016, according to BP’s Statistical Review of World Energy 2017.7 This volume accounts for more than 30% of global LNG trade. Kuwait imports LNG volumes that travel northward through the Strait of Hormuz. At its narrowest point, the Strait of Hormuz is 21 miles wide, but the width of the shipping lane in either direction is only two miles wide, separated by a two-mile buffer zone. The Strait of Hormuz is deep enough and wide enough to handle the world's largest crude oil tankers, with about two-thirds of oil shipments carried by tankers in excess of 150,000 deadweight tons coming through this Strait.

Pipelines available as bypass options

Most potential options to bypass Hormuz are currently not operational. Only Saudi Arabia and the United Arab Emirates (UAE) have pipelines that can ship crude oil outside of the Persian Gulf and have additional pipeline capacity to circumvent the Strait of Hormuz. At the end of 2016, the total available crude oil throughput pipeline capacity from the two countries combined was estimated at 6.6 million b/d, while the two countries combined had roughly 3.9 million b/d of unused bypass capacity (Table 2). Saudi Arabia has the 746-mile Petroline, also known as the East-West Pipeline, which runs across Saudi Arabia from its Abqaiq complex to the Red Sea. The Petroline system consists of two pipelines with a total nameplate (installed) capacity of about 4.8 million b/d. The 56-inch pipeline has a nameplate capacity of 3 million b/d. The 48-inch pipeline had been previously operating as a natural gas pipeline, but Saudi Arabia converted it to an oil pipeline. The switch increased Saudi Arabia's spare oil pipeline capacity to bypass the Strait of Hormuz from 1 million b/d to 2.8 million b/d, but this volume is only achievable if the system operates at its full nameplate capacity. In 2016, Saudi Aramco announced that it plans to expand the capacity of the East-West pipeline to 7 million b/d, with a scheduled completion by end-2018. To date, there has been little progress on the pipeline expansion. Saudi Arabia also operates the Abqaiq-Yanbu natural gas liquids pipeline, which has a capacity of 290,000 b/d. The UAE operates the Abu Dhabi Crude Oil Pipeline (1.5 million b/d) that runs from Habshan (a collection point for Abu Dhabi's onshore oil fields) to the port of Fujairah on the Gulf of Oman, which allows crude oil shipments to circumvent the Strait of Hormuz. The government plans to increase the capacity of this pipeline to 1.8 million b/d.

Figure 3. Map of the Strait of Hormuz Source: U.S. Department of State

Other pipelines are currently unavailable as bypass options

Saudi Arabia has two additional pipelines that run parallel to the Petroline system and bypass the Strait of Hormuz, but neither of the pipelines has the ability to transport additional volumes of oil if the Strait of Hormuz is closed. The 1.65 million b/d, 48-inch Iraqi Pipeline in Saudi Arabia (IPSA), which runs parallel to the Petroline from pump station #3 (11 pumping stations run along the Petroline) to the port of Mu'ajjiz, just south of Yanbu, Saudi Arabia, was built in 1989 to carry 1.65 million b/d of crude oil from Iraq to the Red Sea. The pipeline closed indefinitely following the August 1990 Iraqi invasion of Kuwait. In June 2001, Saudi Arabia seized ownership of IPSA as compensation for debts Iraq owed and converted it to transport natural gas to power plants. Other pipelines, such as the Trans-Arabian Pipeline (TAPLINE) running from Qaisumah in Saudi Arabia to Sidon in Lebanon or a strategic oil pipeline between Iraq and Turkey, have been out of service for years because of war damage, disuse, or political disagreements. These pipelines would require extensive renovation before they could transport oil. Relatively small quantities, several hundred thousand barrels per day at most, could also be transported by truck if the Strait of Hormuz were closed. Table 2. Operating pipelines that bypass the Strait of Hormuz, 2016 Pipeline name Country Status Capacity Throughput Unused capacity Petroline (East-West Pipeline) Saudi Arabia Operating 4.8 1.9 2.9 Abu Dhabi Crude Oil Pipeline United Arab Emirates Operating 1.5 0.5 1.0 Abqaiq-Yanbu Natural Gas Liquids Pipeline Saudi Arabia Operating 0.3 0.3 0.0 Iraqi Pipeline in Saudi Arabia (IPSA) Saudi Arabia Converted to natural gas 0.0 - 0.0 Total 6.6 2.7 3.9 Note: All estimates expressed in million barrels per day (b/d). Unused capacity is defined as pipeline capacity that is not currently used but can be readily available.

Sources: U.S. Energy Information Administration, Lloyd’s List Intelligence.

Strait of Malacca

The Strait of Malacca, linking the Indian Ocean and the Pacific Ocean, is the shortest sea route between the Middle East and growing Asian markets. Flows through the Strait of Malacca rose to 16 million b/d in 2016, retaining its position as the second busiest transit chokepoint.

The Strait of Malacca, located between Indonesia, Malaysia, and Singapore, links the Indian Ocean to the South China Sea and to the Pacific Ocean. The Strait of Malacca is the shortest sea route between Persian Gulf suppliers and the Asian markets—notably China, Japan, South Korea, and the Pacific Rim. Oil shipments through the Strait of Malacca supply China and Indonesia, two of the world's fastest-growing economies. This Strait is the primary chokepoint in Asia, with an estimated 16.0 million b/d flow in 2016, compared with 14.5 million b/d in 2011. Crude oil generally makes up between 85% and 90% of total oil flows per year, and petroleum products account for the remainder (Table 3). At its narrowest point in the Phillips Channel of the Singapore Strait, the Strait of Malacca is only about 1.7 miles wide, creating a natural bottleneck with the potential for collisions, grounding, or oil spills.8 According to the International Maritime Bureau's Piracy Reporting Centre, piracy, including attempted theft and hijackings, is a threat to tankers in the Strait of Malacca, and ships saw an increasing number of attacks in 2015. Data for 2016 were not available at the time of publication.9 If the Strait of Malacca were blocked, nearly half of the world's fleet would be required to reroute around the Indonesian archipelago, such as through the Lombok Strait between the Indonesian islands of Bali and Lombok, or through the Sunda Strait between Java and Sumatra.10 Rerouting would tie up global shipping capacity, add to shipping costs, and potentially affect energy prices. Several proposals have been made to build bypass options and reduce tanker traffic through the Strait of Malacca. In particular, China and Myanmar (Burma) commissioned the Myanmar-China natural gas pipeline in 2013 that stretches from Myanmar's ports in the Bay of Bengal to the Yunnan province of China. The pipeline has a capacity of 424 billion cubic feet per year. The oil portion of the pipeline was completed in August 2014 and it is now operational at full capacity since the 260,000 b/d refinery in Yunnan, China, began operating in June 2017. The Myanmar-China oil line transports Middle Eastern oil, allowing it to bypass the Strait of Malacca.11 The Strait of Malacca is also an important transit route for liquefied natural gas (LNG) from Persian Gulf and African suppliers, particularly Qatar, to East Asian countries with growing LNG demand. The biggest importers of LNG in the region are Japan and South Korea.

Table 3. Strait of Malacca oil and liquefied natural gas (LNG) flows, 2011-16 million barrels per day 2011 2012 2013 2014 2015 2016 Total oil flows through Strait of Malacca 14.5 15.1 15.4 15.5 15.5 16.0 crude oil 12.8 13.2 13.3 13.3 13.9 14.6 refined products 1.7 1.9 2.1 2.2 1.6 1.4 LNG (Tcf per year) 2.8 3.5 3.9 4.1 3.6 3.2 Notes: Tcf = Trillion cubic feet.

Sources: U.S. Energy Information Administration analysis based on Lloyd’s List Intelligence, IHS Waterborne, BP.12

Figure 4. Map of the Strait of Malacca Source: CIA Factbook

Suez Canal/SUMED Pipeline

The Suez Canal and the SUMED Pipeline are strategic routes for Persian Gulf oil and natural gas shipments to Europe and North America. These two routes combined accounted for about 9% of the world’s seaborne oil trade in 2015.

Suez Canal

The Suez Canal is located in Egypt and connects the Red Sea and the Gulf of Suez with the Mediterranean Sea. In 2016, total petroleum and other liquids (crude oil and refined products) and LNG accounted for 17% and 6% of total Suez cargoes, measured by net metric tonnage, respectively. The Suez Canal cannot handle Ultra Large Crude Carriers (ULCC) and fully laden Very Large Crude Carriers (VLCC) class crude oil tankers. The Suezmax was the largest ship that could navigate through the canal until 2010, when the Suez Canal Authority extended the canal depth to 66 feet to allow more than 60% of all tankers to transit the Canal, according to the Suez Canal Authority. In addition, almost 93% of bulk carriers and 100% of container ships have been able to transit the Suez Canal since 2010.13 In 2016, 3.9 million b/d of total oil (crude oil and refined products) transited the Suez Canal in both directions, according to data published by the Suez Canal Authority. Northbound flows rose by about 300,000 b/d in 2016, but southbound shipments decreased for the first time since at least 2009. Increased crude oil exports from Iraq and Saudi Arabia to Europe contributed to higher northbound traffic, while lower exports of petroleum products from Russia to Asia contributed the most to lower southbound traffic. Most oil transiting the Suez Canal was sent northbound (2.4 million b/d) toward European and North American markets, and the remainder was sent southbound (1.5 million b/d), mainly toward Asian markets. Oil exports from Persian Gulf countries (Saudi Arabia, Iraq, Kuwait, United Arab Emirates, Iran, Oman, Qatar, and Bahrain) accounted for 84% of Suez Canal northbound oil flows. The largest importers of northbound oil flows through the Suez Canal in 2016 were European countries (78%) and the United States (14%). Oil exports from Russia accounted for the largest share of (17%) of Suez southbound oil flows, followed by Turkey (15%) and Netherlands (11%). North Africa (Algeria and Libya) made up 12% of the southbound flow. The largest importers of Suez southbound oil flows were Asian countries, with Singapore, China and India accounting for more than 50% of the total. Total traffic through the Suez Canal has been steadily increasing since 2009, and total oil flows rose to more than 2 million b/d by 2014. The increase in oil shipments during 2015 and 2016 in particular reflect increased OPEC production and exports, including increased output in Iraq and Saudi Arabia, and increased exports from Iran in 2016 as sanctions targeting its oil exports were eased.

SUMED Pipeline

The 200-mile long SUMED Pipeline, or Suez-Mediterranean Pipeline, transports crude oil through Egypt from the Red Sea to the Mediterranean Sea. The crude oil flows through two parallel pipelines that are 42 inches in diameter, which have a total pipeline capacity of 2.34 million b/d. Oil flows north starting at the Ain Sukhna terminal along the Red Sea coast to its end point at the Sidi Kerir terminal on the Mediterranean Sea. SUMED is owned by the Arab Petroleum Pipeline Company, a joint venture between the Egyptian General Petroleum Corporation (50%), Saudi Aramco (15%), Abu Dhabi's International Petroleum Investment Company (15%), multiple Kuwaiti companies (15%), and Qatar Petroleum (5%). 14 The SUMED Pipeline is the only alternate route to transport crude oil from the Red Sea to the Mediterranean Sea if ships cannot navigate through the Suez Canal. Closure of the Suez Canal and the SUMED Pipeline would require oil tankers to divert around the southern tip of Africa, the Cape of Good Hope, which would add approximately 2,700 miles to the transit from Saudi Arabia to the United States. The increased transit time would also increase costs and shipping time, according to the U.S. Department of Transportation.15 According to the International Energy Agency (IEA), shipping around Africa would add 15 days of transit to Europe and 8–10 days to the United States. 16 Fully laden VLCCs going toward the Suez Canal also use the SUMED Pipeline for lightering. Lightering occurs when a vessel needs to reduce its weight and draft by offloading cargo to enter a restrictive waterway, such as a canal. The Suez Canal is not deep enough for a fully-laden VLCC and, therefore, a portion of the crude is offloaded at the SUMED Pipeline at the Ain Sukhna terminal. The now partially-laden VLCC goes through the Suez Canal and picks up the offloaded crude at the other end of the pipeline at the Sidi Kerir terminal. In 2016, 1.6 million b/d of crude oil was transported through the SUMED Pipeline to the Mediterranean Sea, and then loaded onto tankers for seaborne trade. Flows via SUMED were relatively unchanged compared with 2015. Total oil flows via SUMED and the Suez Canal were 5.5 million b/d in 2016, 100,000 b/d more than in 2015. Total oil flows via the Suez Canal and SUMED pipeline accounted for about 9% of total seaborne-traded oil in 2015. Table 4. Suez Canal and SUMED pipeline flows of oil and liquefied natural gas (LNG), 2011-16 million barrels per day 2011 2012 2013 2014 2015 2016 Total oil flows via the Suez Canal and SUMED pipeline 3.8 4.5 4.6 5.2 5.4 5.5 Suez Canal total flows crude oil 0.7 1.4 1.5 1.8 1.6 1.8 refined products 1.4 1.6 1.7 2.0 2.2 2.0 total oil 2.2 2.9 3.2 3.7 3.8 3.9 LNG (Tcf per year) 2.1 1.5 1.2 1.2 1.3 1.2 Suez northbound flows crude oil 0.5 0.9 1.1 1.4 1.2 1.4 refined products 0.9 0.8 0.7 0.8 0.8 1.0 total oil 1.4 1.7 1.9 2.1 2.1 2.4 LNG (Tcf per year) 1.8 1.2 1 0.9 1.1 0.8 Suez southbound flows crude oil 0.2 0.5 0.4 0.4 0.4 0.4 refined products 0.6 0.8 1 1.2 1.4 1.1 total oil 0.8 1.3 1.3 1.6 1.7 1.5 LNG (Tcf per year) 0.2 0.3 0.2 0.3 0.3 0.3 SUMED pipeline crude oil flows 1.7 1.5 1.5 1.5 1.6 1.6 Notes: Totals may not exactly match corresponding values as a result of independent rounding. Tcf = Trillion cubic feet.

Source: U.S. Energy Information Administration analysis based on Lloyd’s List Intelligence, Suez Canal Authority (with EIA conversions).

Liquefied natural gas (LNG)

LNG flows through the Suez Canal in both directions were 1.2 Tcf in 2016, accounting for 9% of total LNG transported worldwide.

LNG flows through the Suez Canal in both directions were 1.2 trillion cubic feet (Tcf) in 2016, accounting for about 9% of total LNG traded worldwide. Southbound LNG transit mostly originates in Nigeria, France (as re-exports), and Trinidad and Tobago, mostly destined for Egypt, Jordan, and Japan, which combined account for more than 65% of the total southbound LNG imports through the canal. Nearly all of the northbound transit (99%) is from Qatar and is mainly destined for European markets. The rapid growth in LNG flows through the Suez Canal after 2008 represents the expansion of LNG exports from Qatar. LNG flows through the Suez Canal in both directions have declined from their peak of almost 2.1 Tcf in 2011. The decrease mostly reflects the fall in northbound LNG flows and is consistent with LNG import data for the United States, which show that total LNG imports fell dramatically between 2011 and 2016. U.S. LNG imports from Qatar fell from 91 billion cubic feet in 2011 to zero in 2014 and have remained at this level since then. The changes reflect growing domestic natural gas production in the United States, a decrease in LNG demand in some European countries, and strong competition for LNG in the global market. As a result, Suez LNG flows as a share of total LNG traded worldwide fell to 9% in 2016, compared with 18% in 2011.

Figure 5. Map of Suez Canal/SUMED pipeline Source: U.S. Energy Information Administration, IHS EDIN.

Bab el-Mandeb

Closing the Bab el-Mandeb Strait could keep tankers in the Persian Gulf from reaching the Suez Canal and the SUMED Pipeline, diverting them around the southern tip of Africa.

The Bab el-Mandeb Strait is a chokepoint between the Horn of Africa and the Middle East, and it is a strategic link between the Mediterranean Sea and the Indian Ocean. The strait is located between Yemen, Djibouti, and Eritrea, and it connects the Red Sea with the Gulf of Aden and the Arabian Sea. Most exports from the Persian Gulf that transit the Suez Canal and the SUMED Pipeline also pass through Bab el-Mandeb. An estimated 4.8 million b/d of crude oil and refined petroleum products flowed through this waterway in 2016 toward Europe, the United States, and Asia, an increase from 3.3 million b/d in 2011. The Bab el-Mandeb Strait is 18 miles wide at its narrowest point, limiting tanker traffic to two 2-mile-wide channels for inbound and outbound shipments. Closure of the Bab el-Mandeb could keep tankers originating in the Persian Gulf from reaching the Suez Canal or the SUMED Pipeline, diverting them around the southern tip of Africa, which would add to transit time and cost. In addition, European and North African southbound oil flows could no longer take the most direct route to Asian markets via the Suez Canal and Bab el-Mandeb.

Table 5. Bab el-Mandeb oil flows, 2011-16 million b/d 2011 2012 2013 2014 2015 2016 Total oil flows 3.3 3.6 3.8 4.3 4.7 4.8 Northbound 2.0 2.0 2.1 2.2 2.5 2.8 Southbounds 1.3 1.6 1.7 2.1 2.2 2.0 Note: Totals may not exactly match corresponding values as a result of independent rounding.

Sources: U.S. Energy Information Administration analysis based on Lloyd’s List Intelligence, Suez Canal Authority, and GTT, using EIA conversion factors.

Figure 6. Map of Bab el-Mandeb Source: CIA Factbook

Turkish Straits

Although still an important chokepoint for petroleum liquids transit from the Caspian Sea region, the Turkish Straits have seen declining transit volumes since 2011, falling to 2.4 million b/d in 2016. Oil moving through these straits supplies Western and Southern Europe.

The Turkish Straits, which includes the Bosporus and Dardanelles waterways, divide Asia from Europe. The Bosporus is a 17-mile waterway that connects the Black Sea with the Sea of Marmara. The Dardanelles is a 40-mile waterway that links the Sea of Marmara with the Aegean and Mediterranean Seas.17 Both waterways are located in Turkey and supply Western and Southern Europe with oil from Russia and the Caspian Sea region. An estimated 2.4 million b/d of crude oil and petroleum products flowed through the Turkish Straits in 2016. More than 80% of this volume was crude oil. These Black Sea ports are among the primary oil export routes for Russia and other Eurasian countries including Azerbaijan and Kazakhstan. Oil shipments through the Turkish Straits decreased from 2.9 million b/d in 2011 to 2.4 million b/d in 2016. At its peak, more than 3.4 million b/d transited the straits in 2004, but the volume that traveled through the Turkish Straits fell in the mid-2000s as Russia shifted crude oil exports away from the Black Sea and toward the Baltic ports. Subsequent increases in production and exports from Azerbaijan and Kazakhstan resulted in an increase in shipments through the Turkish Straits, but the increasing trend did not last: Turkish Straits have seen a steady decrease in traffic over the past five years. These volumes may increase in the future as Kazakhstan’s production of crude oil increases and the country exports more crude oil via Black Sea. EIA expects Kazakhstan’s crude oil production to increase through at least the end of 2018 as volumes from the country’s Kashagan field continue to rise. Only half a mile wide at the narrowest point, the Turkish Straits are among the world’s most difficult waterways to navigate because of their sinuous geography. About 48,000 vessels transit the straits each year, making this area one of the world’s busiest maritime chokepoints.18 Commercial shipping has the right of free passage through the Turkish Straits in peacetime, although Turkey claims the right to impose regulations for safety and environmental purposes. Bottlenecks and heavy traffic also create problems for oil tankers in the Turkish Straits.

Figure 7. Map of Turkish Straits Source: U.S. Government

Panama Canal

The Panama Canal is not a significant route for U.S. petroleum trade. The recently completed expansion of the canal is unlikely to significantly change crude oil and petroleum product flows, with the exception of U.S. propane exports. Crude oil and petroleum liquids tankers accounted for a small portion of total transit traffic through the canal in 2016.

The Panama Canal is an important route connecting the Pacific Ocean with the Caribbean Sea and the Atlantic Ocean. The canal is 50 miles long and only 110 feet wide at its narrowest point—the Culebra Cut—at the Continental Divide.19 More than 13,000 vessels transited the Panama Canal in fiscal year 2016, representing roughly 204 million tons of cargo.20 Goods originating in or traveling to the United States accounted for more than 67% of the total shipments passing through the Panama Canal during 2016; China’s share was a distant second at roughly 19%.21 Alternatives to the Panama Canal include the Straits of Magellan, Cape Horn, and Drake Passage at the southern tip of South America, but these routes would significantly increase transit times and costs, adding about 8,000 miles of travel. Although petroleum and petroleum products represented 27% of the principal commodities that crossed through the Panama Canal from the Atlantic to the Pacific in 2016, that canal is not a significant route for global petroleum and petroleum product transit. Northbound (Pacific to Atlantic) traffic of petroleum and petroleum products accounted for only 9% of the total products traveling through the canal.22 In 2015, 1.7% of total global maritime petroleum and petroleum product flows went through the Panama Canal. According to the Panama Canal Authority, 921,000 b/d of petroleum and petroleum products were transported through the canal in fiscal year 2016, of which 843,000 b/d were refined products and the remainder was crude oil.23 About 84% of total petroleum (775,000 b/d) went southbound from the Atlantic to the Pacific in 2016.24 Some oil tankers, such as the ULCC (Ultra Large Crude Carrier) class tankers, can be nearly five times larger than the maximum capacity of the canal. To make the canal more accessible, the Panama Canal Authority, the body that operates the Canal, undertook an expansion program that was completed in June 2016. With the expansion, the Panama Canal Authority inaugurated a third set of locks that allows larger ships to transit the canal. This expansion was the first one since the canal was completed in 1914.25 The canal expansion involved deepening and widening some portions of the canal and constructing an additional, larger set of locks. Unlike the old lock system, which had two lanes of side-by-side traffic, the new set of locks is one large lane and allows four transits per day, supplementing the 25 daily transits using the older lock system. The wider and deeper navigation channels and larger locks allow for the transit of larger vessels through the canal. The maximum vessel dimensions in the old lock system, known as Panamax vessels, limited tankers to those of approximately 300,000 to 500,000 barrels of capacity of petroleum products such as gasoline and diesel fuel. The newer lock system allow the larger Neopanamax vessels to transit the canal, with estimated petroleum product capacities of 400,000 to 600,000 barrels (Figure 8). The expansion of the Panama Canal is not likely to affect crude oil and petroleum product flows in the future, with the exception of U.S. propane exports. Previously, the size limitations of the canal created logistical bottlenecks for U.S. propane exports travelling to markets in Asia, necessitating ship-to-ship transfers. The new, larger Panama Canal locks allow most Very Large Gas Carriers (VLGC), the type of ship that carries propane and other hydrocarbon gas liquids (HGL), to transit.

Figure 8. Panama Canal and Lock System Source: U.S. Energy Information Administration

Figure 9. Panama Canal size restrictions

Figure 10. Map of Panama Canal Source: CIA World Factbook

Table 6. Panama Canal and oil flows, 2011-16 thousand barrels per day 2011 2012 2013 2014 2015 2016 Panama Canal total flows total oil 768 813 863 877 1031 934 crude oil 121 120 92 133 134 79 refined products 647 693 771 744 897 855 Panama Canal southbound flows total oil 609 696 719 701 826 785 crude oil 69 72 40 48 60 47 refined products 541 624 679 653 766 738 Panama canal northbound flows total oil 158 117 144 176 205 149 crude oil 52 48 52 84 74 32 refined products 106 69 92 91 131 116 Notes: Totals may not equal the sum of the components due to independent rounding. Data for the Panama Canal are by fiscal years (October 1 to September 30).

Sources: U.S. Energy Information Administration analysis based on Lloyd’s List Intelligence, Panama Canal Authority (with EIA conversions).26

Trans-Panama Pipeline

The Trans-Panama Pipeline (TPP), operated by Petroterminal de Panama, S.A. (PTP), is located outside the former Canal Zone near the Costa Rican border. It runs from the port of Charco Azul on the Pacific coast to the port of Chiriqui Grande in Bocas del Toro, Panama, on the Caribbean Sea. The pipeline began operating in 1982 with the original purpose of facilitating crude oil shipments from Alaska's North Slope to refineries in the Caribbean and in the U.S. Gulf Coast.27 However, in 1996, the TPP was shut down as oil companies began shipping Alaskan crude oil along alternate routes. In August 2010, the flow of the TPP was reversed, and the pipeline now transports oil from the Caribbean to the Pacific.28 In 2012, BP and PTP signed a seven-year transportation and storage agreement allowing BP to lease storage facilities located on the Caribbean and Pacific coasts of Panama and to use the pipeline to transport crude oil to U.S. West Coast refiners. According to PTP, BP has leased 5.4 million barrels of PTP's storage and committed to east-to-west shipments through the pipeline averaging 100,000 b/d. The route reduces the transport time and the costs of ships that have to travel around Cape Horn at the southern tip of South America to get to the U.S. West Coast.29 Shell, also reportedly signed a three-year agreement to lease capacity in early 2017, gaining access to storage and transshipment facilities, the pipeline network, and tanker docks for oil loading.30 According to Lloyd’s List Intelligence, 111,000 b/d of crude oil was transported through the pipeline to the port of Charco Azul in 2016.

Danish Straits

The Danish Straits are a vital route for Russian seaborne oil exports to Europe.

The Danish Straits are a series of channels that connect the Baltic Sea to the North Sea. They are an important route for Russian seaborne oil exports to Europe. An estimated 3.2 million b/d of crude oil and petroleum products flowed through the Danish Straits in 2016. Russia shifted a significant portion of its crude oil exports to its Baltic ports after opening the port of Primorsk in 2005. In 2011, Primorsk oil exports accounted for almost half of all exports through the Danish Straits, although the volume fell to 32% in 2016. A small amount of oil (less than 50,000 b/d), primarily from Norway and the United Kingdom, also flowed eastward to Scandinavian markets in 2016.

Figure 11. Map of Danish Straits Source: CIA Factbook

Cape of Good Hope

Although not a chokepoint, the Cape of Good Hope is a major global trade route. Crude oil flows around the Cape accounted for about 9% of all seaborne-traded oil.

The Cape of Good Hope, located on the southern tip of South Africa, is a significant transit point for oil tanker shipments around the globe. EIA estimates about 5.8 million b/d of seaborne-traded crude oil moved around the Cape of Good Hope in both directions in 2016. In 2015, crude oil transit around the Cape accounted for roughly 9% of global maritime trade of 5.1 million b/d. In 2016, 4.3 million b/d of crude oil around the world moved eastbound, originating mostly from Africa (2.2 million b/d) and from South America and the Caribbean (1.6 million b/d). Eastbound crude oil flows were nearly all destined for Asian markets (4.1 million b/d). In the opposite direction, nearly all westbound flows originated from the Middle East (1.5 million b/d), mostly destined for the Americas, with the United States accounting for the majority of the total (75% of total flows). Europe was the destination for less than 12% of the flows. The Cape of Good Hope is also an alternate sea route for vessels traveling westward that want to bypass the Gulf of Aden, Bab el-Mandeb Straits, and/or the Suez Canal. However, diverting vessels around the Cape of Good Hope increases costs and shipping time. For example, closure of the Suez Canal and the SUMED Pipeline would require oil tankers to divert around the Cape of Good Hope, adding approximately 2,700 miles to transit from Saudi Arabia to the United States, which would increase both costs and shipping time, according to the U.S. Department of Transportation.31 According to the International Energy Agency (IEA), shipping around Africa would add 15 days of transit to Europe and 8—10 days to the United States.32

Table 7. Crude oil transit via the Cape of Good Hope, 2011-16 million b/d 2011 2012 2013 2014 2015 2016 Total flows 4.7 5.4 5.1 4.9 5.1 5.8 Eastbound 2.9 3.7 3.7 3.8 4.1 4.3 Westbound 1.8 1.7 1.4 1.1 1.0 1.5 Notes: Totals may not equal the sum of the components due to independent rounding.

Sources: U.S. Energy Information Administration analysis based on Lloyd’s List Intelligence

Notes

Data presented in the text are the most recent available as of July 25, 2017

Data are EIA estimates unless otherwise noted.

Endnotes

http://go.usa.gov/xUymB

South Korea imported some 353,000 bpd of Iranian crude last month, up 17 percent on March ahead of the removal of sanction waivers that granted South Korea and another seven countries to legally import certain amounts of Iranian crude despite U.S. sanctions.

A month earlier, South Korea’s imports of Iranian crude reached 1.2 million tons, or 8.8 million barrels which was a 23-percent increase on February and a fivefold increase on January, when Korean refiners resumed their purchases of Iranian crude.

Reuters reports the monthly rise will be followed by a sharp drop this month as Washington did not renew the sanction waivers for Iranian oil importers. The picture would be the same for Japan as the two are the staunchest U.S. allies in Asia and have been careful to maintain their traditionally strong relationship with Washington.

Both South Korea and Japan stopped importing Iranian oil well before the U.S. sanctions snapped back last November and then they waited for a couple of months before they started importing oil from Iran while the waivers lasted. Neither South Korea nor Japan expect any major negative impact from the cancelation of the waivers, officials from the two countries have said. However, now they will have to find an affordable alternative to Iranian oil, especially condensate, of which South Korea is a major importer.

One obvious alternative would be U.S. light crude, which is comparable in quality with Iranian condensate. South Korea is already the second-largest oil client of the U.S. as of the end of 2018, after Canada and ahead of China. The average daily intake of U.S. crude in South Korea last year was 236,000 bpd. This is actually lower than what South Korea imported from Iran during the waiver period, at 235,533 bpd for January to April this year, but now that the waivers have been removed, shipments of U.S. light will most likely increase.

By Irina Slav for Oilprice.com

More Top Reads From Oilprice.com:

https://oilprice.com/Latest-Energy-News/World-News/South-Korean-Oil-Imports-From-Iran-Jumped-17-In-April-Before-Drop.html&ct=ga&cd=CAIyGjk5YzNmM2Y0NmU2Yjk4MTk6Y29tOmVuOkdC&usg=AFQjCNGX_dgzLJnIp3NrrIFe2kWP88pfX

The marine industry’s January 2020 shift to using very low sulfur fuel oil (VLSFO) to power ships worldwide will launch a one- to five-year disruption in oil and refined products markets, according to a study released Thursday by Boston Consulting Group.

The International Maritime Organization (IMO)’s mandated switch will require fuels to have a sulfur content below 0.5%, compared with 3.5% now. It aims to improve human health by reducing air pollution from sea-going vessels.

The changeover may increase profits for refiners, especially on the U.S. Gulf Coast, where plants are designed to process high-sulfur crudes. It could also benefit producers of shale oil, which has a lower sulfur content than other varieties, the study found.

Conversely, prices for high-sulfur fuel oil (HSFO) or bunker fuel, with a maximum sulfur content of 3.5%, will fall as demand erodes, according to the study.

“The effects will be more than made up for by higher market prices for VLSFO and middle distillates, leaving most refiners, particularly complex refiners on the U.S. Gulf Coast, with substantially higher margins than they had before the disruption,” it said.

Prices for crude oil from shale fields will benefit from the transition, the study said, and “command a rising price premium, due to a sulfur concentration that is lower than that of oil from other sources.”

The shortest period for the transition would be one year if the IMO, a United Nations body regulating the shipping industry, were to postpone the start to 2022, allowing refiners and shippers more time to prepare for the change, which was first announced in 2016.

The longest period – five years – would be expected if the world economy falls into recession and shippers widely do not comply with the regulation, narrowing the expected price spread between HSFO and VLSFO.

https://www.reuters.com/article/us-shipping-fuel-study/coming-marine-fuel-standard-will-disrupt-markets-for-1-5-years-bcg-study-idUSKCN1SM0AG

Delek US's Crude Oil Gathering System In The Midland Basin

Crude oil gathering systems do just that — they gather crude from multiple well sites — but the drivers behind their initial development can vary widely. Some gathering systems are developed by oil producers to reduce their use of trucks and more efficiently transport increasing volumes of crude from the lease to takeaway pipelines. Others are the brainchildren of savvy midstream companies that see an opportunity to serve multiple producers in a fast-growing production area. And then there are systems like the one refiner Delek US is now expanding in the Permian’s Midland Basin near the company’s Big Spring, TX, refinery. It’s designed to feed locally produced crude directly to that refinery — and possibly other Delek refineries too — and may potentially be used to help fill a long-haul takeaway pipeline that Delek still hopes to co-develop with partners.

Delek is a mid-size refiner based in Brentwood, TN — also home to Dolly Parton and a number of other country music stars. The company owns and operates four refineries: El Dorado, AR (capacity, 80 Mb/d); Tyler, TX (75 Mb/d), Krotz Springs, LA (74 Mb/d), and Big Spring, TX (73 Mb/d). For many years now, the El Dorado refinery has been receiving a portion of its crude oil needs from Delek’s 600-mile SALA gathering system in southern Arkansas and Louisiana; that system in 2018 transported more than 16 Mb/d, on average, most of it to the El Dorado refinery. Since early 2018, Delek has been developing an approximately 200-mile gathering system in the Midland Basin. The first elements of that $210 million system were completed in the second half of 2018 and have been in service for several months. The rest is under construction and expected to be finished this summer. The system’s initial throughput capacity is 150 Mb/d; with the ongoing build-out, that will double to 300 Mb/d.

The new gathering system already provides much of the crude needed by Delek US’s Big Spring refinery (red dot in Figure 1), which is one of only two refineries located within the Permian Basin proper, the other being HollyFrontier’s 100-Mb/d Navajo refinery (blue dot) in Artesia, NM. (As we mentioned at the outset, we also think the new Big Spring gathering system may have the potential to feed Midland-sourced barrels to other Delek refineries too. More on that in a moment.) Delek so far has released only a few specifics about the system, which runs (or soon will run) through parts of four West Texas counties — Howard, Borden, Martin and Midland (yellow rectangles) — and gathers crude from wells on the more than 200,000 acres dedicated to the system. The company has indicated that the system will include at least 650 Mbbl of storage capacity.

Figure 1. Delek’s Big Spring Gathering System, and Selected Pipelines and Pipeline Projects. Source: RBN

The Big Spring refinery (photo below) that the new gathering system feeds is located in Howard County, about 40 miles east of Midland. The refinery was acquired by Delek US in July 2017 as part of its purchase of the rest of Alon Energy USA in a Texas two-step style of company takeover. Big Spring is Delek’s smallest refinery by capacity (albeit just barely), but it’s also its most sophisticated. Put another way, Big Spring is chock full of equipment to break down two readily available, local crude types — West Texas Intermediate (WTI) and West Texas Sour (WTS) into a wide range of valuable refined products, including gasoline, ultra-low-sulfur diesel (ULSD) and jet fuel. [As we said last June in Heavy, WTS — the heavier, more sour counterpart to WTI — has a lower API gravity than WTI (32 to 35 degrees vs. 37 to 42) and higher sulfur content (1.5% vs. 0.45%), and therefore requires a more intense degree of refining to break the crude down into the most valuable mix of refined products — something the Big Spring refinery can easily do.]

A major driver behind the Big Spring gathering system’s development is to provide Delek’s Big Spring refinery with access to Midland crude directly from wells, which will enable the company to better control oil quality. As we said in Refinery Yields Forever, the output of a refinery (how much gasoline, diesel, jet fuel, etc. it produces per barrel of crude) — and, as a result, the refinery’s profitability — depends on a number of factors, including the refinery’s equipment, how the refinery is operated, and the characteristics of the crude oil (API gravity, sulfur content, etc.) that the refinery processes. In You Can’t Always Get Out What You Put In, we explained that crude oil characteristics can vary widely depending on where the oil is produced — even within a major production area like the Permian — and the commingling of crudes from various sources in big, long-haul pipelines can leave a refinery at the end of those pipes with crude that is less than ideal for its needs.

Delek US’s Big Spring Refinery. Source: Delek

By owning the gathering pipe, and sophisticated electronics and measuring devices supporting it, Delek gains a line-of-sight directly to the source barrel. It knows where the high-gravity and low-gravity wells are, and which are the best wells to get flowing into its refinery. Based on what crude slate it wants to run, it could segregate some barrels in storage, picking which to use for the refinery, and possibly turning away crude that doesn’t fit its specific needs into the downstream pipes the system connects to. Delek also knows what each individual well is producing, and has the ability to schedule volumes into pipes and its refinery, giving it a huge degree of flexibility (also responsibility!). But instead of producers telling Delek, say, five days late that they are a bit short of production this month, Delek will know every day what is coming out of the ground.

We should note here that we also see the potential for the Midland crude gathered on Delek’s new Big Spring system to find its way to one and possibly two or three other Delek refineries. Our understanding is that Delek holds firm capacity on Energy Transfer’s 40-Mb/d Amdel Pipeline (yellow line in Figure 1) from the Midland/Big Spring area to Nederland, TX; from there, crude from the Big Spring system could be barged up to Delek’s Krotz Springs refinery in Louisiana. We also know that Plains All American’s Mesa Pipeline (green line) and Sunrise Pipeline (red line) — both of which tie into Plains’ large Basin Pipeline System (pink lines) — have connections with the Big Spring refinery, which suggests that Mesa and Sunrise could potentially be used to transport crude from the Big Spring gathering system to Colorado City, TX. From there, other pipes could be used to move the crude to Delek’s Tyler refinery, and maybe to its El Dorado refinery too.

As for the potential tie-in between the Big Spring gathering system and a new long-haul pipe to the coast that we mentioned in our intro, Magellan Midstream Partners, Energy Transfer, MPLX and Delek announced in September 2018 that they were planning the 600-mile Permian Gulf Coast (PGC) Pipeline (dashed orange line in Figure 1), which would’ve had the capacity to transport between 600 Mb/d and 1 MMb/d from Midland to both Houston and Energy Transfer’s terminal in Nederland, TX. However, that plan later unraveled — Magellan, Energy Transfer and Delek withdrew from the PGC project in the first quarter of this year and said they were exploring other alternatives, and MPLX announced on May 8 that it has signed a letter of intent to participate in the 1-MMb/d-plus Wink-to-Webster Pipeline (dashed blue line) being co-developed by Plains, ExxonMobil and Lotus Midstream. (We should note that the planned Wink-to-Webster pipe will run through Midland — and very near the new Big Spring gathering system — on its way to the Gulf Coast.)

In sum, Delek US appears to have taken an innovative approach to gathering-system development — its focus being on gathering Midland crude with specific characteristics for its Big Spring refinery — and possibly for other Delek refineries as well. By calibrating the Big Spring refinery to optimize output when running locally sourced crude with specific qualities, and then delivering that crude directly from nearby wells via a company-owned gathering system, Delek can have a high degree of confidence that the refinery will always be operating at the top of its game.

In addition to the crude-quality benefit, the Big Spring gathering system (1) will allow Delek to receive the revenue associated with gathering crude, (2) will expand Delek’s revenue- and profit-generating logistics business, and (3) provides a potential source of barrels for a new long-haul pipeline from the Permian to the Gulf Coast that Delek hopes to be involved in co-developing. Delek Logistics Partners, a master limited partnership (MLP) in which Delek US holds a more than 60% ownership interest, is managing the development of the new gathering system, and Delek has indicated that it is likely to “drop down” ownership of the gathering system to the MLP when the system is fully operational. In our next blog in this series, we’ll look at another major gathering system in the nation’s hottest crude oil production area.

https://rbnenergy.com/have-it-all-part-5-delek-uss-crude-oil-gathering-system-in-the-midland-basin

Russia's Transneft to compensate buyers for dirty oil, but they must prove loss

Russia’s state pipeline monopoly Transneft will compensate all parties for losses incurred from contaminated oil, but they must prove the damage, a government official said on Thursday, as the first European refinery declared force majeure.

Russia’s oil export flows have been disrupted since April when high levels of organic chloride were found in crude pumped via the Druzhba pipeline to the Baltic port of Ust-Luga and other European countries.

The Druzhba pipeline splits in Belarus into a northern spur to Poland and Germany and a southern leg via Ukraine to Slovakia, Hungary and the Czech Republic. Only Hungary has resumed test flows to see if its refinery equipment can withstand the contaminated oil.

Druzhba can pump 1 million barrels of oil per day (bpd) or the equivalent of 1 percent of global oil demand.

Transneft has repeatedly said that oil firms which use chloride to boost oil output were to blame for contamination, but on Thursday, Russia said Transneft would foot the bill.

“Of course - and sadly - Transneft,” Russian Deputy Prime Minister Dmitry Kozak told reporters when asked who would pay after a meeting with his Belarusian counterpart Igor Lyashenko in Moscow. Transneft head Nikolai Tokarev also attended the meeting.

Ukraine and Belarus both said they will ask Transneft for compensation. Stoppage of oil flows not only affects refineries but also budget revenues from a loss of transit fees.

Kozak said on Thursday that Russia had not yet calculated the cost of the damage and it would take three to four weeks to do so.

“This is not a judicial dispute, we will find a compromise,” Kozak said. “Everyone who can prove real losses will, of course, be compensated.”

He said Poland, Ukraine, Hungary and Slovakia were currently waiting and had not yet issued demands for compensation.

According to traders, while Druzhba remains shut, Russia is losing $80 million a day. For the buyers of an estimated 19 million barrels of contaminated crude which is stuck in the pipeline and loaded on tankers, it’s a $1.2 billion question.

FIRST VICTIM

According to the International Energy Agency, the impact on European refinery throughput in the second quarter of 2019 from the contaminated crude is seen at roughly 250,000 barrels per day, under 2% of the continent’s product demand.

Some countries, including the Czech Republic, have had to use strategic oil reserves to make up for lost Russian barrels, while Poland has increased seaborne oil imports.

Total’s 230,000 barrel-per-day Leuna refinery in Germany, which usually receives Urals crude via Druzhba, declared force majeure on refined product shipments on Thursday as a result of the contamination.

Total had no immediate comment.

Industry monitor Genscape said it detected abnormal emissions at the plant and decreased furnace stack activity on the 112,000 bpd vacuum distillation unit. “Activity from all other monitored units has remained at operational levels,” Genscape said on Thursday.

Kozak said it will take 22 days to clean one branch of Druzhba and seven days for the other, without specifying which was which. He added that the prime ministers of Russia and Belarus were due to meet next week to discuss the issue.

https://www.reuters.com/article/us-russia-oil-total/russias-transneft-to-compensate-buyers-for-dirty-oil-but-they-must-prove-loss-idUSKCN1SM1XC

China has issued a second batch of refined fuel export quotas for this year totaling 23.79 million tonnes, about 30 percent more than the first batch, trading sources briefed on the matter said.

The quotas comprised 9.09 million tonnes of gasoline, 9.175 million tonnes of diesel and 5.525 million tonnes of jet fuel, the two sources said.

China manages annual fuel exports by issuing quotas progressively in batches.

The increased quotas come as China has been boosting its exports of refined products, with record refinery production exceeding domestic fuel demand growth.

The fuel surplus is set to grow further, as privately owned Hengli Petrochemical Co Ltd’s 400,000 barrels-per-day plant in northeast China ramps up to full capacity later this month.

The second batch of quotas, which will be valid until the end of the year, brings the total issued so far for 2019 to 42.15 million tonnes.

All the quotas were issued to state oil companies - CNPC, Sinopec, CNOOC, Sinochem and China National Aviation Fuel, the sources said.

They will also fall under the category of general trade, under which refiners will receive tax refunds for exports of fuel products, they said.

https://uk.reuters.com/article/china-oil-export-quotas/update-1-china-issues-2nd-batch-of-2019-fuel-quotas-up-30-pct-on-1st-batch-traders-idUKL4N22T0CT

OPEC’s key ally in all production cut agreements since 2017—Russia—appears to have somewhat reluctantly agreed to cut output in each of the OPEC/non-OPEC pacts over the past two years. 

Now that the next OPEC and allies’ meeting at the end of June is set to discuss a potential production increase to offset mounting supply disruptions, instead of cuts, Russia seems to be all in on joining a pact to reverse some or all of the current 1.2 million bpd cuts that OPEC and its Moscow-led non-OPEC allies are implementing until June this year.

Russia is not giving away any official indications as to its thinking about the OPEC+ deal. Comments and hints from officials and companies, however, indicate the usual reluctance to continue cutting production once the current agreement expires in June. 

A panel of OPEC and non-OPEC partners is meeting in Jeddah, Saudi Arabia, this weekend, to discuss the state of the oil market. No one expects any decision to be taken at this meeting, which is a kind of a preparatory meet-up before the full OPEC and non-OPEC line-up gathers in Vienna on June 25 and 26.

But at this weekend’s meeting, discussion is expected to revolve around a possible production increase after the end of the U.S. sanction waivers to all Iranian oil buyers. Talk of raising—instead of cutting—production would be in line with Russia’s ambition to resume pumping more as its companies benefit from higher production as much as from higher oil prices and have seen their new field production plans stalled by Russia’s commitments to the OPEC+ deals.

Russia is likely to tell the panel meeting in Jeddah that it could increase its production by 300,000 bpd in a short period of time, Maksim Nechaev, Russia director for IHS Markit, told Bloomberg this week.Related: The IEA's Dire Warning For Energy Markets

Russia has a far from perfect track record when it comes to keeping its commitment to the OPEC+ cuts. It always argues that due to weather and geological challenges, it wants gradual reduction until it reaches its quota. In the current cuts, Moscow hit the reduction target only this month—one month before the six-month pact expires. 

Looking beyond June, Russia has been sending mixed messages to the market in recent months, leaving the market and analysts guessing how Vladimir Putin will approach the deal this time. 

Russia’s biggest oil producer Rosneft, which alongside other Russian companies is said to be reluctant to continue to cut production after June, said this week in its Q1 earnings release that it “has substantial potential to promptly increase production” if restrictions are eased.

Russia’s position on the deal will probably not be known until the very day of the meeting with OPEC at the end of June, so the market and analysts will continue to speculate on the fate of the pact for another month and a half. 

Asked about the meeting in Jeddah this weekend, Russian Energy Minister Alexander Novak said on Wednesday that the OPEC+ alliance feels that it’s still too early to assess how the end of the U.S. waivers for Iranian buyers will impact the oil market as of this month. There are too many uncertainties in the market and it’s too early to talk about possible recommendations to the full OPEC+ meeting at end-June. The Jeddah meeting will assess the current market situation and estimates for future demand and supply, and exchange views, Novak said.Related: OPECs Spare Capacity Could Be Put To The Test

This time around, Russia’s goal to start reversing the cuts it has just achieved coincides with expectations of global supply declines, due to the tightened U.S. sanctions on Iran’s oil exports, plunging Venezuelan production, fear of outages in conflict-torn Libya, and concerns about global oil supply routes with the heightened tension in the Middle East’s most important oil waterways.

“Russia’s interest in raising oil output now coincides with the interest of Saudi Arabia,” Dmitry Marinchenko, a senior director at Fitch Ratings, told Bloomberg.

Saudi Arabia has pledged to fulfill all customer requests for additional barrels from buyers, but it has also said that it won’t be rushing into boosting production in advance until it actually sees Iranian barrels coming off the market and buyers demanding more oil.

An uncontrolled production ramp-up could send oil prices sharply down on oversupply concerns, and this is the last thing Saudi Arabia needs now as it aims to keep oil prices at around and over $70 a barrel Brent for budget revenue purposes.

This weekend’s meeting will be the first official gathering of OPEC and non-OPEC ministers since the U.S. ended the waivers for Iranian oil exports. Although no decisions are expected to be taken in Jeddah, the partners in the deal will exchange views that could be the start of negotiations leading to the end-June meeting.

https://oilprice.com/Energy/Energy-General/Russia-Hints-At-OPEC-Deal-Exit.html