Friday, July 20, 2018

Do changes in trade flows impact the tanker market?

http://www.divergingmarkets.com/wp-content/uploads/2013/04/2013.04.16.Global-Shipping-Routes.png

Poten & Partner’s weekly opinion piece recently looked at nearly five years of crude oil trade data (2014 –2018) to see if any interesting trends or developments could be seen. 
 
Are certain segments growing faster than others? How about shifts in export or import regions. Was anything noticed that was not expected?
 
First, the overall crude oil and dirty product trade for 2014-2018 was examined. To make the earlier years comparable with 2018, Poten looked at only the first six months of the year.
 
The data showed that the dirty tanker trade steadily grew during 2014-2017, increasing almost 5% in the first six months of 2015 and still growing 2.2% and 3.3% in 2016 and 2017, respectively.
 
However, in 2018 to date, the total dirty tanker trade (measured in tonnes) was down  1.3% compared to the same period one year ago (tonne/miles:-1.6%).
 
In Asia, modest increases in China and India could not compensate for declines in Japan and Asean countries, so overall tonne/mile demand from Asia was down 1%.
 
The biggest decline in import demand, however, came from the US (-15%). On the other hand, US exports were one of the few bright spots this year to date, with tonne/mile demand more than double that of the same period last year. The long-haul trade to China was responsible for almost 60% of that increase.
 
A review of the largest trade routes confirmed the changes in crude flows. The largest VLCC route was from the Arabian Gulf to the China Sea (China, Taiwan, South Korea) and this has not changed since 2014. This route, which is more than twice the size of the next route (AG –Japan), represents some 30% of the total VLCC trade.
 
However, the AG –US Gulf trade, which ranked No 4 in 2014 declined both in absolute and relative terms. Its volume fell by 33% and it now only ranked sixth.
 
In contrast, the US Gulf –China Sea VLCC trade currently ranks nineth. This trade did not exist prior to 2017. This increase in USG VLCC exports coincided with a decline in Venezuelan exports.
 
Another VLCC trade that has been in decline recently (and quite volatile overall) is that from AG to Europe. After a 55% increase from 2016 to 2017, this trade has fallen by 42% so far this year.
 
Moving onto the Suezmax segment, this trade has developed differently from VLCCs.
 
Suezmax employment has increased steadily since 2014, with a healthy 5% increase thus far this year.
 
A lot of Suezmaxes are employed in shuttle trades offshore Brazil (No 1 in the ranking) and in moving Alaskan crude to the US West Coast (No 3), but these trades are not growing and generate relatively little tonne/mile demand, due to the short distances involved.
 
The same applies to the second largest trade - AG to India.
 
A growing Suezmax trade is the AG –Southern Europe, but this is to a large extent driven by rising exports from Iran, which could be in jeopardy in the second half of this year, due to US sanctions.
 
West Africa exports have been relatively stable in recent years after significant volatility in 2014 –2016.
 
Thus far this year, Suezmax trades from the AG, West Africa, the Black Sea, the US Gulf and from the UK/Cont were growing, while trades originating in the Far East, the Eastern Med and Venezuela were struggling.
 
In the Aframax segment, the intra-Asean Far East (including Indonesia, Thailand, Malaysia, Singapore, etc) has overtaken the Caribbean market as the largest Aframax trading area.
 
Another Asian Aframax trade that is growing in importance is the exports out of Kozmino to China, South Korea and Taiwan.
 
Thus far in 2018, this is the third largest Aframax route (in tonnes), recently overtaking certain trades in the North Sea and the Mediterranean.
 
Overall, Aframax employment is down thus far this year versus 2017 in terms of number of voyages, and barrels moved, but tonne/miles are slightly up, as average distances increased.
 
In total, crude oil tanker demand has been relatively flat and rates are down as a result of increases in fleet size. However, there are a lot of developments hidden under the surface that belie the relative stability of aggregate tanker demand, Poten concluded. 

Thursday, July 19, 2018

US Revokes Citgo CEO’s Visa

 
 CEO of Citgo Petroleum Corp. Asdrubal Chavez

https://www.petroleumafrica.com/us-revokes-citgo-ceos-visa/

The president and CEO of Citgo Petroleum Corp. Asdrubal Chavez, had his US visa revoked. Citgo is the US subsidiary of Venezuela’s state-run PDVSA.

Chavez is the cousin of Venezuela’s late president Hugo Chavez.

US State Department spokesman Noel Clay said the US has broad authority to revoke visas, but does not discuss individual cases because they are confidential under the law.

In a statement on the issue, a Citgo spokeswoman only said that the “day-to-day operations of CITGO remain uninterrupted and senior leadership remains unchanged.”

Wednesday, July 18, 2018

EIA: Seven Major US Shale Regions To Hit New Production Records

File:United States Shale gas plays, May 2011.pdf


Oil production in the seven most prolific US shale regions will hit new highs next month, according to the Energy Information Administration’s monthly Drilling Productivity Report released on Monday afternoon.

Production in the seven regions is expected to increase by 143,000 bpd in August over July’s 7.327 million bpd, according to the EIA.

The news came not even 24 hours after Wood Mackenzie called peak oil demand in 2036 as electric vehicle sales grow , sending oil prices sharply downward on the news.

At 4:15pm EDT, the WTI benchmark was trading down a staggering 4.10% (-$2.91) at $68.10. Brent crude was trading down even more, at 4.50% (-$3.39) at $71.94.

Of the seven more prolific US regions for oil, the Permian is expected to see the biggest increase, at 73,000 bpd, to reach 3.406 million bpd. If this level of production is realized in August, it would represent about a 400,000 bpd climb since January in the Permian alone.
Increases in unconventional oil in the Eagle Ford is thought to come in a distant second, according to the industry body, at an 35,000-bpd increase to reach 1.436 million bpd.

The EIA’s Drilling Productivity Report also tracks drilled but uncompleted wells, which are seen increasing in number for August by 193 across the seven major regions—164 of which are in the Permian. This figure represents one of the largest monthly increases in recent months. The DUC count is of particular concern in the Permian, which is facing takeaway constraints. Some analysts are concerned, according to S&P Global Platts, that if oil and gas cannot be moved out of the Permian due to these constraints in the Permian, the number of wells in the Permian will need to be “banked” until such capacity is brought online.

By Julianne Geiger for Oilprice.com

Tuesday, July 17, 2018

World's Oil Supply Cushion Could Be Stretched to the Limit: IEA

Google Earth

THE world's oil supply cushion could be stretched to the limit due to prolonged outages, supporting prices and threatening demand growth, the International Energy Agency said on Thursday.

The expected drop in Iranian crude exports this year due to renewed US sanctions, a decline in Venezuela's production and outages in Libya, Canada and the North Sea have driven oil prices to their highest since 2014 in recent weeks.

Opec and other key producers including Russia responded to the tightness by easing a supply-cut agreement, with Saudi Arabia vowing to support the market as US President Donald Trump accused the group of pushing prices higher.

The Paris-based IEA said in its monthly Oil Markets Report that there were already "very welcome" signs that output from leading producers had been boosted and may reach a record.

The global energy watchdog, however, said the disruptions underscored the pressure on global supplies as the world's spare production capacity cushion "might be stretched to the limit".

Spare capacity refers to a producer's ability to ramp up production in a relatively short time. Much of it is located in the Middle East.

The IEA said Opec crude production in June reached a four-month high of 31.87 million barrels per day. Spare capacity in the Middle East in July was 1.6 million bpd, roughly 2 per cent of global output.

As US sanctions on Iran are expected to "hit hard" in the fourth quarter of the year, Saudi Arabia could further ramp up output, which would cut the kingdom's spare capacity to an unprecedented level below one million bpd, the IEA said.

Non-Opec production including from surging US shale also continued to rise, but the IEA said that might not be enough to assuage concerns.

"This vulnerability currently underpins oil prices and seems likely to continue doing so. We see no sign of higher production from elsewhere that might ease fears of market tightness," it said.

The IEA maintained its 2018 oil demand growth forecast at 1.4 million bpd, but warned that higher prices could dampen consumption.

"Higher prices are prolonging the fears of consumers everywhere that their economies will be damaged. In turn, this could have a marked impact on oil demand growth."

The IEA said Iran's crude exports could be reduced by significantly more than the 1.2 million bpd seen in the previous round of international sanctions. Iran exports roughly 2.5 million bpd, most of which goes to Asia. China and India, the world's second and third largest oil consumers, could face "major challenges" in finding alternative crude oil following the drop in Iranian and Venezuelan exports, the IEA said.

Iranian crude exports to Europe dropped by nearly 50 per cent in June, the IEA said, as refiners gradually wind down purchases before US sanctions take effect in November.

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Friday, July 13, 2018

Future Iranian exports - the big question

Iran Natural Gas Map


What if US sanctions reduce Iranian exports close to zero? 
 
Most analysts expected the reduction in Iranian exports to be gradual and limited, including Poten & Partners, author of this report. 
 
It was thought the reduction could eventually reach 500-600,000 barrels per day from an average of 2.6 mill barrels per day in 2018 year-to-date. 
 
However, an alternative scenario has been gaining traction, one in which Iranian exports will be reduced even more than during the previous sanctions period.
 
Reports from the US State Department indicate that the Trump administration is not only looking for reductions in exports, similar to those imposed during the Obama administration but also aims to bring Iranian exports down to zero.
 
While this may not be a realistic expectation, the US is expected to use its considerable leverage to force rolling reductions in purchases from all buyers of Iranian crude and waivers are conditional on immediate cuts.
 
The implications of further Iranian export cuts for the tanker market are uncertain; it depends to a large extent on which countries have the spare production capacity to make up the shortfall.
 
The ultimate impact on tanker tonne/mile demand hinges on the resulting changes in trade flows.
 
Iran has ample experience in dealing with various kinds of sanctions and even if the US applies maximum pressure on its trading partners, Iran will have various options to keep at least some of its exports flowing.
 
For example, as sanctions start to bite, it will try to lure buyers with discounts and extended payment terms. To circumvent US banking restrictions, it could accept payment in other currencies or do barter deals and has already agreed to an oil swap with Iraq.
 
Iran will also be using its own tanker fleet (one of the largest in the world) to move and store crude.
 
However, despite Iran’s attempts to minimise the damage, early indications are not encouraging for the country. Most international oil companies, especially those with meaningful US operations, have already decided to steer clear from buying Iranian crude.
 
US allies like Japan and South Korea are under pressure to reduce their purchases. Indeed, South Korea has already dropped imports to zero. Turkey is also a significant buyer of Iranian oil and while they may resist pressure from the US to cut back, they don’t have a lot of room to increase their purchases.
 
The two countries that could take more Iranian crude are the two largest current buyers - India and China. Combined they imported about 1.4 mill barrels per day over the past three months. India is more likely than China to reduce its imports from Iran under US pressure.
 
China, which is already embroiled in a trade conflict with the US has less incentive to comply and may import more (discounted) Iranian crude.
 
So, what happens if US sanctions are so successful that Iranian exports are reduced from 2.6 mill to 1 mill barrels per day by the end of this year?
 
Unfortunately, the Iranian sanctions are not happening in a vacuum. Venezuela’s production is also falling. The IEA estimates that Venezuela’s production capacity will fall a further 550,000 to around 800,000 barrels per day by the end of 2019.
 
Angola is also facing challenges maintaining production. In the short-term Libya and Canada are facing production and export hiccups. In our own backyard, the shale oil producers in Texas have problems bringing their growing crude oil flows to market due to pipeline restrictions and port constraints.
 
Where will the replacement crude oil come from?
 
The only OPEC countries with significant spare capacity are Saudi Arabia, the UAE and Kuwait.
 
Industry experts believe that these countries can sustainably increase production by 1.5 –2 mill barrels per day within 12 months; outside OPEC, Russian producers can reverse their voluntary cutbacks, which will add back 300,000 barrels per day.
 
The bottom-line is: it will be ‘all hands on deck’ for the producers with spare capacity, and in such a scenario, there is a risk of significant price increases.
 
Higher prices will throttle demand growth, in particular in developing countries, which are already facing headwinds with higher oil prices in combination with a strong dollar.
 
A slowdown in global oil demand will also have a negative impact on tanker demand, Poten concluded.

Strait of Hormuz threatened with closure

Iranian President Hassan Rouhani

Iranian President Rouhani has hinted that Iran could disrupt the flow of crude exports out of the Arabian Gulf, while an Iranian Revolutionary Guard commander explicitly stated; "If they want to stop Iranian oil exports, we will not allow any oil shipment to pass through the Strait of Hormuz." 
 
A disruption of this magnitude would result in a monumental shift for both the global oil and oil transportation markets as 979 mill tonnes of dirty and clean cargo passed through this choke point last year, McQuilling Services said in a blog.
 
Roughly one third of global crude exports would be removed from the market, sending crude prices well over $100 per barrel into uncharted territory. Worldwide refiners will look to alternative regions for feedstock requirements after severe drawdowns of existing inventories. 
 
However, it’s unlikely that would offset the negative impacts of a lack of Arabian Gulf flows. This would result in a significant fall in tanker demand as Arabian Gulf tanker exports account for well over 5 trill tonne/miles annually, McQuilling concluded.
 
Meanwhile, US President Trump has criticised OPEC for the recent rise in fuel prices, claiming that the US pays for defence for many of the groups’ members.
 
As a result, OPEC should make an effort to increase crude supply to pressure global pricing, he said. 
 
The closing of the Straits has been threatened many times before, especially during the two Israel/Arab conflicts in the 1960s and 1970s, which resulted in the shutting of the Suez Canal and the Shatt el Arab, plus the Iran/Iraq war in the 1980s when VLCCs/ULCCs ran the gauntlet of missile attacks when shuttling crude from Kharg Island to Hormuz Island - Ed.

Wednesday, July 11, 2018

OPEC's oil output jumps in June as Saudi Arabia opens the taps to tame crude prices

 
Akos Stiller | Bloomberg | Getty Images
Khalid Al-Falih, Saudi Arabia's energy and industry minister, arrives for the 171st Organization of Petroleum Exporting Countries (OPEC) meeting in Vienna, Austria, on Wednesday, Nov. 30, 2016.

  • Saudi Arabia's oil production jumped by nearly 500,000 barrels per day in June as it aims to put more supply into the market to tame the cost of crude.
  • Output from OPEC was up 173,000 bpd as the 15-member producer group prepares to lift production caps in place since 2017.
  • OPEC forecast that global oil demand will cross 100 million bpd for the first time in 2019, but warned trade tensions could negatively impact the market.
Saudi Arabia hiked its oil output in June to the highest level since the end of 2016, as it aims to cool the market after crude prices recently rose to 3½-year highs.

The jump in Saudi supplies shows the world's top crude exporter is making good on its recent vows to tame oil prices. The kingdom has faced pressure from big crude importers like China and India, as well as President Donald Trump, who worry about negative economic impacts from rising fuel costs.
The increase also comes as OPEC forecast global oil demand will surpass 100 million barrels per day (bpd) next year.

Saudi Arabia reported that it pumped nearly 10.5 million bpd last month, up from just more than 10 million bpd in May. Data from independent sources cited in OPEC's monthly report showed a slightly smaller build to just more than 10.4 million bpd.

That pushed production from OPEC to more than 32.3 million bpd in June, up 173,000 bpd from the previous month, according to the independent figures. The cartel's total production got a boost of 331,000 bpd from the Republic of Congo, which began reporting as OPEC's 15th member this month.
OPEC, along with Russia and several other producer nations, has been limiting output since January 2017 in order to drain a crude glut that sent oil prices to 12-year lows in 2016. However, output from the participating nations has fallen much more than expected, largely due to production problems in several of the countries.

At a contentious meeting last month, the cartel agreed to increase output in light of falling production in Venezuela and looming U.S. sanctions on Iran, the world's fifth-biggest oil producer. The producers agreed to start raising output beginning in July, but OPEC's latest monthly report shows several began pumping more last month.

Iraq chipped in the second-biggest increase in June, upping its output by 71,500 bpd to about 4.5 million bpd. Baghdad was one of several countries that initially expressed skepticism about lifting OPEC's production caps.

The United Arab Emirates and Kuwait raised output by 35,100 bpd and 27,300 bpd, respectively. The Arab nations are seen as two of only a handful of OPEC members with spare capacity.

The gains were offset by a 254,000-bpd plunge in production from Libya, where an ongoing political rift shut several of the country's oil ports. Output also continued to decline in Angola and Venezuela, dropping by 88,300 bpd and 47,500 bpd, respectively.

Iran also posted a small drop, bringing its output to about 3.8 million bpd. U.S. demands for oil buyers to cut Iranian imports to zero by November have roiled the market in the last two weeks. However, crude prices eased Tuesday after Secretary of State Mike Pompeo signaled some countries could get waivers.

2019 supply and demand forecast

OPEC also released its initial forecast for oil supply and demand in 2019 on Wednesday.

The group sees demand growth moderating, but still increasing by 1.45 million bpd next year. That would push the world's appetite for oil beyond the 100 million bpd threshold for the first time.

However, OPEC made clear that its view of the global economy assumes there is no significant increase in trade tariffs and that current disputes will soon be resolved. The cartel appeared to be referencing the growing number of trade battles the United States has pursued against China, Europe, Canada and other countries.

"Hence, if trade tensions rise further, and given other uncertainties, it could weigh on business and consumer sentiment," OPEC said. "This may then start to negatively impact investment, capital flows and consumer spending, with a subsequent negative effect on the global oil market.

OPEC expects production from countries outside the group to jump by 2.1 million bpd in 2019, led by surging U.S. output. That means the world will need about 32.2 million bpd from OPEC, or roughly 800,000 fewer bpd than during 2018, the group estimates.

"Therefore, if the world economy performs better than expected, leading to higher growth in crude oil demand, OPEC will continue to have sufficient supply to support oil market stability," the group said.

Tom DiChristopher CNBC
Tom DiChristopherEnergy Reporter

Tuesday, July 10, 2018

Anatomy of Saudi Arabia’s Crude Oil Capabilities

Saudi Arabia Fig 4

It comes with oil prices back on the brink of $80/b spurred by sharp supply outages from Venezuela and Libya and with the potential for the market to tightening further due to looming sanctions on Iran’s oil sector. Saudi Arabia has changed its tone since May, reassuring some of the world’s biggest crude oil consumers, especially the US and India, that it is willing to balance the market.

That has drawn fellow OPEC member Iran’s ire, which has questioned whether changes to its production cut agreement in June to pump an extra 1 million b/d can come at the expense of other member’s market share.

Saudi Arabia, meanwhile, continues to reiterate its readiness to use its spare oil production capacity to meet any future changes in oil supply and demand “when needed”.

The kingdom has always maintained it can boost output by up to 2 million b/d and over the weekend it reassured the US it can deliver.

But S&P Global Platts Analytics believes the global crude market could be left short by that very same 2 million b/d by the end of the year.

The question whether the world’s only swing producer has both the means and the motivation to pump to the maximum to meet global oil supply shortages at short notice and for the long-term therefore needs an answer.

Saudi Arabia’s oil and gas infrastructure

PRODUCTION PROFILE
 
While Saudi Aramco CEO Amin Nasser told Platts recently that “maximum sustainable production” was 12 million b/d up from 10.03 million b/d in May, industry experts believe Saudi Arabia will struggle to pump more than 1 million b/d of additional output.

Platts Analytics says even if Saudi Arabia produces close to 11 million b/d it would be running its system at stress levels.

Saudi crude production averaged 9.96 million b/d from January to May this week, according to Platts OPEC survey data and is set to add at least 300,000 b/d in June according to preliminary survey data as it starts to empty some of its tanks.

Saudi crude output averaged 10.38 million b/d in 2016, before OPEC and non-OPEC started their production cuts.

SPARE CAPACITY
 
EIA defines spare capacity as the volume of production that can be brought on within 30 days and sustained for at least 90 days.

In the longer term Saudi Arabia could possibly reach the 12 million b/d but it would take significant time and investment and doesn’t fit the spare capacity definition.

There is the possibility of an emergency surge in output towards 12 million b/d whereby oil fields are depleted beyond what would be considered a reasonable rate and could end up damaging its production abilities further out.

NEUTRAL ZONE
 
Saudi Arabia shares with Kuwait a partitioned neutral zone that can generate up to 500,000 b/d.
The closure of the key fields, Khafji and Wafra, has led to a political stand-off between the two OPEC producers.

The restarts of these fields will be crucial for the kingdom if it wants to reach its 12 million b/d target.
Earlier this week, Japan’s Toyo Engineering said the Khafji oil field shared by Saudi Arabia and Kuwait is being prepared to restart production in 2019.

Khafji was shut in October 2014 for environmental reasons and Wafra has been shut since May 2015 due to operational difficulties.

Industry experts believe it will take time for production to return should the issue be resolved.

KEY TERMINALS
 
The country’s largest oil export terminals are in the port of Ras Tanura.
 
The port can handle capacity of about 6.5 million b/d, according to the EIA.

All of Saudi’s key crude oil grades load from here along with condensate and products.

The port comprises three terminals: Ras Tanura terminal, Ju’aymah crude terminal, and Ju’aymah LPG export terminal.

The Ras Tanura crude terminal has a 33 million barrels storage capacity.

Sea shipping capacity is crucial to Saudi Arabia given that it lacks international pipelines.

The other key crude export terminal is the King Fahd terminal in Yanbu on the Red Sea, which has a loading capacity of 6.6 million b/d.

Total crude oil storage capacity at the terminal is 12.5 million barrels.

Only Arab Light crude oil grade is loaded at the Yanbu terminal.

Saudi Arabia has other smaller ports, including Ras al-Khafji, Jubail, Jizan, and Jeddah.

KEY BUYERS
 
The main customers of the kingdom’s oil are in Asia, with the region taking almost two-thirds of the country’s oil exports.

Japan, China, India and South Korea are the largest buyers of Saudi crude. The main buyers in this region are China’s Unipec, CNOOC and Sinochem; Japan’s Nippon Oil Corporation, Cosmo Oil, Idemitsu Kosan; and India’s IOC, BPCL and Reliance.

The US, a key ally of the kingdom, is also a sizeable buyer, taking around 15% of Saudi crude exports.

Saudi Aramco operates the 603,000 b/d Port Arthur refinery in Texas, which is a pivotal buyer.

Flows to Europe are around 10% of Saudi crude loadings with the bulk being exported from the Sidi Kerir terminal in Egypt.

CRUDE QUALITY, EXPORT GRADES
 
Saudi crude is generally a mix of heavy to medium sour oil, which is generally high in sulfur and yields a decent amount of residual fuel and vacuum gasoil.

The oil is particularly popular with complex refineries in Asia, US and Europe which can crack heavy sulfurous crudes, and still yield distillate products due to the refiners having complex secondary units.

The key export grades are Arab Heavy, Arab Medium, Arab Light and Arab Extra Light.

Some of Saudi’s key oil fields are Ghawar, Khurais, Shaybah, Safaniyah, Qatif and Zuluf.

EXPORT EXPANSION
 
Saudi Aramco plans to begin exports from the Muajjiz oil terminal on the Red Sea sometime before the end of 2018.

This would raise Saudi Arabia’s total loading and (crude and products) export capacity to about 15 million b/d from 11.5 million b/d.

CRUDE BURN
 
Liquid fuels continue to account for half of the current energy mix.

Saudi Arabia burned an average of 458,000 b/d of crude last year in its power plants, with a peak of 680,000 b/d in June, according to the Riyadh-based Joint Organizations Data Initiative.

The government hopes to increase the share of gas used to 70% over the next 10 years, nearly doubling its current gas production to 23 Bcf/d by 2026.

It processed an all-time high of 12 Bcf/d of raw gas in 2016, producing 8.3 Bcf/d of sales gas.

That was up from around 8 Bcf/d of sales gas in 2015, according to its annual review released in June last year.

Monday, July 9, 2018

Conoco to Depose Citgo in Hunt for PDVSA's Caribbean Assets

Witness swearing on bible telling the truth

ConocoPhillips moved to bring Venezuelan PDVSA's U.S. refining unit Citgo Petroleum into its legal battles to enforce a $2 billion arbitration award against the South American country's nationalization of its Venezuelan assets.

A U.S. district court judge in Houston on Thursday ruled Conoco can depose Citgo as preparation for a court case against PDVSA and others over alleged asset transfers in the Caribbean that Conoco claims were designed to frustrate its efforts to obtain payment under an International Chamber of Commerce (ICC) award.

Citgo declined to comment, citing a policy regarding ongoing litigation.

Conoco is pleased with the court's decision, spokesman Daren Beaudo said in a statement. The company has not received any payment from PDVSA for the award and will continue to pursue the matter, he added.

The decision is another blow to the Venezuelan oil company, which has struggled to pay creditors as its oil production has fallen to the lowest level in more than three decades.

Conoco alleges state-run PDVSA transferred crude and fuels stored at the Isla refinery and Bullenbay Terminal in Curacao to Citgo to prevent it from seizing the oil to enforce the ICC award, according to its filing with a U.S. district in Houston.

The court filing portrays active and often successful efforts by PDVSA and its subsidiary to defeat Conoco's bids to seize oil cargoes and other assets. In one case, it claims PDVSA caused Citgo Petroleum to claim ownership of cargoes off Aruba as a way to lift the company's liens, Conoco said in its June filing.

PDVSA also denied court officers access to some ships docked near Curacao and at least one vessel temporarily disabled its GPS transponder to make a getaway, avoiding seizure, the filing said.

Conoco's assets in Venezuela were expropriated in 2007, after the late President Hugo Chavez nationalized several oil projects by forcing their conversion into joint ventures controlled by PDVSA.
Conoco and Exxon Mobil Corp left Venezuela after they were unable to reach agreements with PDVSA.

As part of the arbitration award, Conoco was able to place liens on assets owned or rented in Curacao, Aruba, Bonaire and St. Eustatius, including inventories held at refineries and terminals, and cargoes aboard vessels.

But those efforts have been hindered by local groups and courts. A Curacao court provisionally lifted Conoco's claims on the Isla refinery in May after public utilities and the island's government petitioned the court, citing their need for the fuels. 

Friday, July 6, 2018

VLCC Markets - Good activity - soft rates

https://i.ytimg.com/vi/ssgxjatQnVo/maxresdefault.jpg


Activity was reported to be very good during the past week for MEG VLCCs.
However, the tonnage build-up from the week before has resulted in softer rates, Fearnleys reported.
 
To have a similar month volume-wise as June, there should be at least 60 deals left for July. Owners left with ships in position were constantly looking for the one factor to inch the rates up a notch.
 
In contrast, activity in USG/Caribs and West Africa stopped, which does not help the MEG/East market for the time being. Singapore bunker prices have risen and could eventually be the decisive factor of turning rates around in owners’ favour.
 
Suezmaxes experienced a week of healthy cargo activity, especially from the Mediterranean/Black Sea and Americas.
 
However, due to sufficient tonnage availability, rates remained flat.
 
Due to higher bunker prices, we might see higher Worldscale rates, however we expect net earnings to stay at today’s level in the near future, Fearnleys said.
 
In the North Sea and Baltic, the market looked soft going into this week.
 
There was a decent amount of tonnage around, and owners were willing to break WS80 for Baltic loading. This made charterers try to secure low rates, but with over five cargoes working in the North Sea at the same time, owners sensed a re-bounce and stood their ground.
 
It was still tight for North Sea cargoes working in the 10-15 window, but after these have been fixed, we believe the market will stabilise around current levels.
 
In the Mediterranean/Black Sea, it has been busy, especially from the Black Sea, but dates are being worked too far forward, and even with the key port of Trieste working at half capacity, owners are struggling to push rates anywhere.
 
With Libya now struggling again, and Black Sea dates running away from owners, we fear there is a very quiet period going forward in this market, Fearnleys concluded.
 
Illustrating the problems in Libya, the National Oil Corporation (NOC) declared force majeure on crude oil loading at Hariga and Zuetina oil terminals on 2nd July, 2018.
 
This announcement followed the suspension of loading at the Ras Lanuf and Es Sider terminals reported earlier.
 
The force majeure is being imposed in line with the order of the Libyan National Army (LNA) General Command to prohibit ports from receiving allocated shipments.
 
 “Despite our warning of the consequences and attempts to reason with the LNA General Command, two legitimate allocations were blocked from loading at Hariga and Zuetina this weekend. The storage tanks are full and production will now go offline,” NOC Chairman Eng Mustafa Sanalla, said, according to a Reuters report.
 
The oil company said that the total production loss amounted to 850,000 barrels per day of crude, 710 mill standard cu ft per day of natural gas, and more than 20,000 barrels per day of condensate.
 
Elsewhere, Euronav Tankers has acquired the ULCC ‘Seaways Laura Lynn’ from Oceania Tanker Corp, a subsidiary of International Seaways (INSW) for $32.5 mill.
 
The Antwerp-based company has renamed the 2003-built, 441,561 dwt tanker ‘Oceania’ and registered her under the Belgian flag.
 
Euronav already owns the other ULCC still operating, the ‘TI Europe’ (2002 – 442,470 dwt).
 
CEO Paddy Rodgers, said: “Bringing the only other ULCC in the world fleet under our control will provide us with a significant strategic opportunity.”
 
TOP Ships has agreed a sale and leaseback and a five-year timecharter with Cargill International for an MR2 newbuilding.
 
The 50,000 dwt ship (Hull No 8242) is currently under construction at Hyundai Mipo Dockyard in South Korea for January, 2019 delivery.
 
Following the sale, TOP Ships will bareboat charter back the vessel and simultaneously put her on a timecharter with Cargill Ocean Transportation.
 
The company also has continuous options to buy back the vessel during the five year sale and leaseback period at the end of which it has to buy it back.
 
The gross proceeds from the sale are $32.4 mill, which is the total amount that remains to be paid for the vessel. In addition, the revenue backlog expected to be generated by the timecharter is about $27.6 mill.
 
According to a report, tanker asset values look set to climb, as the current culling of the fleets older units will help lead to a finer balance between supply and demand.
 
The decision by OPEC and Saudi Arabia to put more barrels into the market should increase the cargo count in the Arabian Gulf. This will lead to a rosier outlook for the second half of the year than many predicted, VesselsValue claimed.
 
LR1s could see the highest gains, as the run up in demand for distillate flows ahead of the 2020 bunker switch over should benefit large clean product tankers.
 
LR1s are currently seeing depressed asset values, and the expected value on mean reversion alone should benefit owners, VesselsValue added.
 
Brokers reported that Delta Tankers has gone on a buying spree netting five Suezmaxes, including three newbuildings, plus three Aframax newbuildings.
 
Most if not all of the tankers were connected with Toisa, which was allowed by a US bankruptcy court to sell its fleet.
 
Waruna was said to have continued its recent buying spree by acquiring the 2003-built Suezmax ‘Mabrouk’ for $14 mill.
 
A couple of Aframaxes were said to have changed hands. These were the 2003-built ‘Kaluga’ thought sold to Greek interests for $9.5 mill and the 2007-built ‘BM Bonanza’ said to have also been taken by Greek interests for $17 mill.
 
NORDEN was believed to have sold the 2005-built Handysize ‘Nord Farer’ for $11.5 mill to Nigerian interests, while the two years older Handysize ‘Nicos Tomasos’ was said to have gone to undisclosed interests for $8.6 mill.
 
In the MR segment, Greek interests were believed to have purchased the 2010-built ‘Axel’ for $16.6 mill, while Far East buyers were thought to have acquired the 2000-built ‘Ocean Coral’ for $6 mill.
 
Returning to the charter market, among the latest fixtures recorded was the 2018-built VLCC ‘Lita’ said to have been fixed to ExxonMobil for seven years at $31,000 per day.
 
Another VLCC - the 2016-built ‘Atromitos’ - was thought bareboat chartered to AISSOT for five years at $23,500 per day.
 
Petrobras was said to have fixed the LR2 ‘United Grace’ for two years at $15,750 per day, while ST Shipping was believed to have taken the 2009-built MR ‘FPMC 19’ for 12 months at $12,000 per day.
 
In the newbuilding sector, Chinese leasing concern BoComFL has ordered another Suezmax at Hyundai Samho bringing the total up to nine, while Eastern Pacific was said to have contracted two Aframaxes at Hanjin Subic Bay for $43 mill each.
 
Empire Navigation was believed to have signed a letter of intent (LoI) for four, option four, MRs with Hyundai Mipo for about $37 mill each. They will be Tier III compliant and will be built on the back of a long term charter to Cargill.
 
Teekay Offshore Partners was rumoured to have ordered another two 158,000 dwt shuttle tankers at Samsung Heavy Industries.
 
The pair is set for delivery in 2021, according to the data from Asiasis.

Thursday, July 5, 2018

Fourth of July gas prices: Don't fill up in these states on your roadtrip



So, you're taking a road trip for the Fourth of July weekend, and you're about to leave the state.
Do you fill up on gas now, or do you wait to fill up after you cross the border?

Making the wrong decision could cost you more than $10 a tank, depending on where you're heading.
"Watch out for those state lines," says Patrick DeHaan, senior petroleum analyst at fuel-station-finding app GasBuddy.

Gas prices averaged $2.86 per gallon Tuesday, according to AAA, hitting a four-year high for Independence Day travel.

Here's some advice before you head out – all prices according to GasBuddy:

1. Fill up in Arizona, not California

The price disparity between these two states is extreme.
Arizona averaged $3.06 per gallon as of Tuesday, while California averaged $3.73, according to GasBuddy.
At those prices, a 15-gallon fill-up is $10.06 more expensive in California.

2. Fill up in Texas, not New Mexico

If you're road-tripping in the Southwest, price differences can be significant. This is another good example.
The price of fuel in Texas, where oil refineries are clustered, averaged $2.66 on Tuesday. In New Mexico, it was $2.91.
That means you'd save $3.75 in Texas on a 15-gallon tank.

3. Fill up in Louisiana, not Texas

But Texas is more expensive than Louisiana, which is also a hot spot for refineries. 
Prices averaged $2.59 in Louisiana on Tuesday, compared with $2.66 in Texas.
Generally, though, "anywhere in the South" is a good place to fill up, DeHaan said. "They’re right in oil’s backyard. Plus, low taxes."

4. Fill up in Ohio, not Michigan

Ohio is much more forgiving on the pocketbook than its rival to the north. 
With prices averaging $2.79 on Tuesday, Ohio was sharply lower than Michigan's $2.96.

5. Fill up in Virginia, not West Virginia

Going white-river rafting in West Virginia? Sounds fun.
But fill up first in Virginia, where prices are 21 cents lower at $2.61.

6. Fill up in West Virginia, not Pennsylvania

West Virginia doesn't look so bad when you see prices in Pennsylvania, which averaged $3.01 on Tuesday, compared with West Virginia's $2.82.

7. Fill up in Massachusetts, not Connecticut 

At $2.91, Massachusetts isn't exactly an oasis of cheap gas.
But it's still cheaper than neighboring Connecticut at $3.08.

8. Fill up in South Carolina, not North Carolina

North Carolina is 14 cents higher at $2.66.
Come to think of it, fill up in South Carolina no matter where you're heading. It's the cheapest gas state in the country, according to GasBuddy.

Tuesday, July 3, 2018

Glencore Shares Tumble After U.S. Subpoena

Workers at a Glencore mine in Quebec. Glencore said the subpoena was dated July 2 and relates to its operations in Congo, Nigeria and Venezuela from 2007 to the present.
Workers at a Glencore mine in Quebec. Glencore said the subpoena was dated July 2 and relates to its operations in Congo, Nigeria and Venezuela from 2007 to the present. Photo: Valerian Mazataud/Bloomberg News


By Scott Patterson

LONDON— Glencore GLNCY -9.05% PLC said it received a subpoena from U.S. authorities related to compliance with American corruption and money-laundering laws at its operations in Congo, Nigeria and Venezuela—a move that significantly ratchets up government scrutiny of the mining and trading giant.

The Tuesday disclosure rattled investors. Glencore shares fell more than 12% in early London trading before recovering slightly to trade down 4% in the afternoon.

Glencore said the U.S. Justice Department issued a subpoena demanding it hand over documents and other records related to compliance with the U.S. Foreign Corrupt Practices Act and U.S. money laundering statutes. FCPA is an antibribery law that forbids the bribing of foreign officials to win, or keep, business. Glencore said it was reviewing the request and would provide further details “as appropriate.” A spokesman declined to comment further.

The company said the subpoena was dated July 2 and relates to its operations in the three countries from 2007 to the present.

Glencore’s mining operations in the Democratic Republic of Congo have been the subject of scrutiny by foreign governments and corruption watchdogs. But its oil operations in Venezuela and Nigeria haven’t surfaced before as a subject of interest by government officials.

The broad scope of the subpoena—covering practices in three different countries over more than a decade—suggests “there is a relatively thorough investigation at hand,” said Tyler Broda, an analyst at RBC Capital Markets.

Glencore is one of the world’s largest diversified mining companies and is also among the world’s largest traders of commodities, including coal, oil and copper. It employs 146,000 people in more than 50 countries. The company was formed in 1994 when its current chief executive, Ivan Glasenberg, and a team of executives bought out controversial financier Marc Rich for $1.2 billion. 

Among the world’s mining giants, Glencore has pushed the furthest into politically risky countries. That has left it open in many cases to heightened inspection in some of those countries, where the rule of law can be weaker. Some of Glencore’s biggest competitors, like Australia’s BHP Billiton Ltd. , have tried to pivot to more developed countries, seen as less risky.

Recently, Mr. Glasenberg has found himself caught between the Trump administration and Moscow as Washington ratchets up sanctions on Russia. Glencore owns about 9% of United Rusal, Russia’s biggest aluminum maker. That company, and its major owner, Russian billionaire Oleg Deripaska, have been sanctioned by Washington for his perceived closeness to President Vladimir Putin. Mr. Glasenberg stepped down from the company’s board in April because of the sanctions. Mr. Deripaska has said sanctions against him and his entities are “baseless.”

Glencore’s biggest regulatory headache, however, has been Congo. It operates a pair of giant copper mining operations that also produce cobalt, a key ingredient of lithium-ion batteries that power mobile phones and electric vehicles. Congo accounts for more than 60% of the world’s cobalt production. Prices for the metal have soared.

Nearly 10% of Glencore’s metals and minerals revenue came from Congo and Zambia in 2017, a figure that is likely to rise in coming years as the company increases production at its mining operations there. 

The Congo operations have received increased scrutiny in recent years in part because of the company’s ties to Israeli diamond tycoon Dan Gertler. In December, the U.S. Treasury Department sanctioned Mr. Gertler for alleged corruption in Congo, a move that prohibits U.S. companies from having financial ties with him and that temporarily forced Glencore to cancel tens of millions of dollars in payments to him. Mr. Gertler is a friend of Congolese President Joseph Kabila, according to the Treasury Department. Mr. Gertler, through a spokesman, has denied wrongdoing.

Glencore and Mr. Gertler’s company, Fleurette Group, separately bought shares of Nikanor PLC, a company listed in London that owned a large copper mine. To expand, Nikanor’s owners, including Mr. Glasenberg, sought to merge with another Congo mining company, Katanga Mining . A tie-up between Katanga and Nikanor was sealed in January 2008, creating one of Congo’s largest copper-mining companies. 

Glencore then agreed to buy out Mr. Gertler’s stakes in their joint businesses, and in early 2017 Glencore paid about $1 billion for them. The relationship has nevertheless come under foreign legal scrutiny. The Wall Street Journal reported last year that Canada’s Ontario Securities Commission, the country’s biggest securities regulator, is probing more than $100 million in payments Katanga made to a company controlled by Mr. Gertler. Glencore and Mr. Gertler have both said the payments were made appropriately.

Following the Treasury Department’s sanctions against Mr. Gertler in December, Glencore suspended its payments for the stake sale to the Israeli billionaire. Mr. Gertler, in response, sued Glencore in Congo, seeking $3 billion in damages. 

In June, Glencore said it would resume the payments, saying it was its only viable option to avoid the risk of losings its copper mines. The company said it would make the payments in euros, distancing the transactions from the U.S. financial system. 

Hours after Glencore announced its move, the Treasury Department ratcheted up the heat, imposing new sanctions on 14 entities affiliated with Mr. Gertler. A spokesman for Fleurette Group declined to comment on the new round of sanctions when they were announced. 

Write to Scott Patterson at scott.patterson@wsj.com

Monday, July 2, 2018

ExxonMobil Issues Best-Practice Tips for Switching to Low Sulphur Fuel

Image result for exxon mobil

Guidance comes ahead of the International Maritime Organization’s (IMO) 2020 0.5 per cent global sulphur cap.

The fuels landscape is set to dramatically change when the International Maritime Organization’s (IMO) 0.5 per cent sulphur cap comes into force on 1 January, 2020. Ahead of this, ExxonMobil has developed top tips to help the marine industry switch to low sulphur fuels while maintaining a vessel’s safe and reliable operation.
First, establish best practice
Prevention is always better than cure, so it is advisable to
  • Buy fuel that meets the latest ISO 8217:2017 specification
  • Only bunker from reputable fuel suppliers
  • Clean out bunker tank residues when necessary
Test for cat fines
Some new 0.5 per cent sulphur fuels could contain elevated levels of cat fines which, if not properly treated, could trigger catastrophic engine damage. If laboratory testing shows a high concentration, then:
  • Maintain storage tank temperatures at least 10°C above fuel pour point
  • Keep settling tanks at 85°C
  • Operate purifiers at optimum efficiency and minimum throughput
  • Drain water from fuel tanks to aid settling
Check for compatibility
There is a risk that two compliant fuels will not be compatible, which can trigger sludge formation. It is therefore essential to:
  • Test the fuels for compatibility, ideally in a laboratory.  If the fuel is already loaded, then test onboard to get immediate results
  • Store fuels separately until testing has been carried out
  • Even when two fuels are compatible, avoid mixing in excess of 80:20
Monitor for sludge
If sludge does start to form, it is essential to ensure against further fuel blending before any remedial action is taken, as this may exacerbate the problem. Then:
  • Operate two or more separators in parallel at their lowest throughput
  • Increase the frequency of purifier discharge
  • Monitor and clean filters frequently
With so many different types of fuel potentially set to enter the bunker market, vessel operators are rightly concerned about stability, compatibility and quality issues, such as elevated levels of cat fines,” said John LaRese, Marine Fuels Technical Advisor, ExxonMobil. “It will therefore be more important than ever for operators to follow best practice when bunkering compliant fuels, including using laboratories to test fuel samples for potential issues.

Sunday, July 1, 2018

Trump Asks Saudi Arabia to Pump More Oil, Citing High Prices

President Donald Trump and Saudi Arabia's King Salman shake hands during a signing ceremony at the Saudi Royal Court in Riyadh on May 2017.
President Donald Trump and Saudi Arabia's King Salman shake hands during a signing ceremony at the Saudi Royal Court in Riyadh on May 2017. Photo: bandar al-jaloud/Agence France-Presse/Getty Images 
 

By: Summer Said in Dubai 

U.S. President Donald Trump said he asked Saudi Arabia to significantly boost its oil production, ratcheting up pressure on Riyadh to help ease fast-rising crude prices.

The intervention comes as global demand is rising, inventories of stored oil are falling and a number of supply disruptions—in Canada, Iran, Libya and Venezuela—have tightened markets.

Oil prices ended Friday at another multiyear high. U.S. benchmark crude finished just over $74 a barrel, its highest since November 2014. Brent, the global benchmark, is close to $80 a barrel.

That has contributed to rising gasoline prices, just ahead of U.S. midterm elections. Mr. Trump has targeted the Organization of the Petroleum Exporting Countries in recent months, blaming it for the higher prices.
Saudi Arabia, the de facto head of OPEC, and Russia have already said they would work together to boost production. Producers get more revenue when prices are high but are also mindful that when they get too high, they can slow economic growth—and oil demand. OPEC has also said it listened to complaints from big consuming nations, like the U.S.

Publicly, Riyadh has committed to only modest output increases, but behind the scenes the kingdom is ramping up quickly—moving from just over 10 million barrels a day a few months ago to a target of close to 11 million barrels a day by July, according to people close to the Saudi oil ministry.

Mr. Trump on Saturday said in a tweet he is asking for even more, a request that oil officials inside and outside the kingdom say would be hard for Saudi Arabia to meet on a sustainable basis.
“I am asking that Saudi Arabia increase oil production, maybe up to 2,000,000 barrels,” Mr. Trump said in the tweet, citing a conversation with Saudi King Salman.

“Prices to [sic] high! He has agreed!” the tweet said, citing “turmoil & disfunction” in Iran and Venezuela. It wasn’t clear whether Mr. Trump was saying the king agreed that prices were too high or that the kingdom would increase oil output. 

A senior Saudi official said the kingdom has made no specific promise to Mr. Trump but rather assured the U.S. of its capability to meet demand.

On Saturday night, about 14 hours after Mr. Trump posted his tweet, the White House put out a statement on the call between the president and King Salman, which took place Friday.

The statement doesn’t say that King Salman agreed to ramp up oil production or that he agreed prices were too high.

“In response to the president’s assessment of a deficit in the oil market, King Salman affirmed that the kingdom maintains a two million barrel per day spare capacity, which it will prudently use if and when necessary to ensure market balance and stability, and in coordination with its producer partners, to respond to any eventuality,” the statement reads.

Some experts said they didn’t believe the dramatic increase Mr. Trump called for was necessary. With global economic growth expected to slow in the next two years, producing more oil now could lead to another surplus, said Dean Foreman, the chief economist at the American Petroleum Institute. The previous global surplus, due in part to ramped-up U.S. shale production, pushed oil prices as low as $25 a barrel.

“The market doesn’t need another two million barrels a day right now,” Mr. Foreman said.

Venezuela production has dropped amid an economic crisis there. The U.S. has reimposed sanctions on Iran and earlier this week said it was asking buyers of Iranian crude to stop their purchases by November, a much sooner cutoff than expected.

Oil prices had started to fall in recent weeks, thanks to the Saudi and Russian agreement to increase production. But they started climbing fast again this week.

Prices at the pump have a long history as an issue ahead of U.S. elections. Republicans in November are trying to hold on to majorities in both chambers of Congress.

Democrats have sought to capitalize on the issue. Ahead of the Memorial Day holiday in May, Senate Minority Leader Chuck Schumer (D., N.Y.) appeared at an Exxon Mobil Corp. gas station in Washington, D.C., and blamed Mr. Trump for high gas prices. “Why doesn’t he ask them to lower their prices so that the prices at the pump can be lower?” he said.

In an official statement posted on the state-run Saudi Press Agency, Saudi Arabia said King Salman spoke to Mr. Trump but gave no mention of the two million barrels of extra production the American leader tweeted about.

“During the call, the two leaders stressed the need to make efforts to maintain the stability of oil markets and the growth of the global economy,” it said.
 
Saudi Arabia, while a close U.S. ally, has been wary of appearing to respond to specific requests to pump oil. It says it acts to balance markets, keeping prices not too high or low. It is also eager to appear to be acting in coordination with OPEC.

Iran, a fellow OPEC member, has accused Riyadh of doing Washington’s bidding. Iran’s OPEC governor told Bloomberg on Saturday that Mr. Trump was calling on Saudi “to walk out from OPEC.”

Last week, OPEC and a group of non-OPEC producers led by Russia agreed to ease up on a 2016 pact that limited production. The new deal would allow about 600,000 barrels a day of new oil, according to people familiar with the matter.

Tanks and oil pipes at Saudi Aramco's Ras Tanura oil refinery and terminal on May 21.
Tanks and oil pipes at Saudi Aramco's Ras Tanura oil refinery and terminal on May 21. Photo: ahmed jadallah/Reuters 
 
Most of that increase was expected to come from Saudi Arabia, which is almost alone in the world in having spare capacity that it can quickly turn on. It says it keeps between 1.5 million barrels and 2 million barrels a day of spare capacity at the ready at all times.

Its ability to deliver that in a sustainable way is debatable, according to officials and outsiders.

People familiar with the matter have previously said the kingdom can only sustain output of about 12.5 million barrels a day for a short period.

“Saudi Arabia does not really like going beyond 11 million barrels a day and has no intension of expanding its current production capacity. It is expensive,” another Saudi official said.

The U.S., too, is pumping flat out. U.S. output is almost 11 million barrels a day, according to federal estimates. Shale producers are facing infrastructure hurdles that are threatening to slow growth.

In some ways, shale producers and OPEC are aligned. They both want prices high enough to profit, but not so high that it might destroy demand.

“Shale producers don’t want prices to fall to $40 again, where most can’t make a profit and drill economic wells,” said Kirk Edwards, president of Latigo Petroleum. “There needs to be a perfect balance, and there’s a chance that these supply issues will leave a big hole out there that needs to be filled.”

Write to Summer Said at summer.said@wsj.com, Mark H. Anderson at mark.anderson@wsj.com and Peter Nicholas at peter.nicholas@wsj.com