The developer of the private equity-backed EPIC natural gas liquids pipeline will temporarily convert the conduit to carry crude oil as bottlenecks in America’s hottest shale play threaten to curtail production.
Oil service on the third and final phase of EPIC Midstream Holdings LP’s NGL pipeline is expected to start in the third quarter of next year, the company said in a statementFriday. That would offer interim relief to producers in the prolific Permian Basin of West Texas and New Mexico, a region facing a dearth of pipeline capacity until late 2019, when new projects are expected to enter service.
The pipeline crunch is forcing Permian producers to sell crude locally at a steep discount to prices on the Gulf Coast. Oil sold in Midland, in the heart of the play, for $15.60 a barrel less than in Houston on Friday, after starting the year at a $3.40 discount. That comes as output in the basin soars, with researcher IHS Markit predicting supply will reach 5.4 million barrels a day by 2023 -- more than every OPEC country except Saudi Arabia.
EPIC’s NGL system will be able to carry 400,000 barrels per day of crude until its oil pipeline, which will run alongside the NGL line, enters service by January 2020. The company had previously said the crude pipeline would enter service in the second half of 2019.
In the same statement, the company said it had received enough commitments to expand the crude pipeline to transport 600,000 barrels per day, with the ability to increase capacity to 900,000 barrels per day.
Noble Energy Inc., Apache Corp. and Diamondback Energy Inc., shippers on the crude pipeline, will have service on the converted liquids pipeline. Both the NGL and crude pipeline are backed by Ares Management LP’s private equity group.
By David Marino and Rachel Adams-Heard
(Bloomberg) --Natural gas has begun flowing again on a pipeline in British Columbia after a rupture on an adjacent line forced oil refineries in Washington to cut output and sent gasoline prices soaring up and down the West Coast.
An explosion Tuesday on Enbridge Inc.’s Westcoast Mainline gas system rippled through energy markets in the Pacific Northwest. Late Thursday, Enbridge announced it had begun pumping gas through a 30-inch (76-centimeter) line that is in the same right of way as the 36-inch pipe that burst. The smaller conduit, shut as a precautionary measure after the rupture, will be returned to about 80 percent of its capacity.
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Fortis Inc., a Canadian company that distributes gas from the system, askedcustomers to “avoid nonessential use of gas until the situation is completely resolved” because supplies are still tight.
Williams Cos. said it’s working with local distribution companies to supply residential and other “critical gas users” with fuel shipped on its Northwest Pipeline. Starting Thursday, the Williams line will be able to draw up to 1.2 billion cubic feet per day of gas from a storage facility in southwest Washington, which is being placed back into service after it underwent scheduled maintenance.
Natural-gas pipeline rupture cuts off fuel supply to Washington refineries
The Enbridge pipeline is part of its Westcoast Energy network, and carries as much as 2.9 billion cubic feet of gas a day -- supplying half of the demand from Washington, Oregon and Idaho -- from the Fort Nelson processing plant in northern British Columbia to the U.S. border. The 1,751-mile (2,818-kilometer) line connects to gas fields as far north as the Yukon and Northwest Territories.
About 100 people in the Lheidli T’enneh First Nation were evacuated Tuesday evening after the line ruptured in a rural area outside of Prince George. Enbridge said the incident is under investigation. Canada’s Transportation Safety Board was heading to the scene on Thursday morning.
The National Energy Board issued an order late Wednesday local time saying that Enbridge could only restart the adjacent line at reduced pressure. Pipeline companies often route multiple lines within the same right-of-way to minimize the impact on the environment and surrounding landowners. The company can apply to resume full pressure, the regulator said in a statement on its website.
The ruling Kurdistan Democratic Party (KDP) was leading in a parliamentary election in the semi-autonomous Kurdistan Region of Iraq with 85 percent of votes counted, the election commission said on Thursday.
A year after a failed bid for independence, Iraq’s Kurds voted on Sunday in a parliamentary election that could disrupt the delicate balance of power in the region.
With 85 percent of ballots counted, the KDP was leading with 595,592 votes, the Independent High Elections and Referendum Commission (KHEC) said in a news conference.
Its historic rival and junior coalition partner in government, the Patriotic Union of Kurdistan (PUK), was in second place with 287,575 votes.
The commission said it had received and was investigating 1,045 complaints, which is why it had not published final results.
On Sunday, the PUK said it might not recognise the results of the election due to what it described as violations in the voting process, and then appeared to backtrack, injecting uncertainty into the process.
Election observers also said there were irregularities.
With opposition parties weak, the KDP and PUK are likely to extend their almost three decades of sharing power, but the preliminary results suggest that Masoud Barzani’s KDP will take a dominant position in Kurdish politics.
The two parties, who fought a civil war in the 1990s but more recently have taken to sharing power, have just come out of a gruelling political battle in Baghdad, where they competed for the presidency of federal Iraq. The PUK came out on top with the election of Barham Salih.
The largest Kurdish opposition party, Gorran, or Movement for Change, was in a distant third with 164,336 votes. There are 111 seats in the Iraqi Kurdistan Parliament, with 11 reserved for minority groups.
The far-right Brazilian populist Jair Bolsonaro has secured a resounding victory in the first-round of his country’s presidential election, but fallen just short of the majority required to avoid a second-round run-off.
After a campaign as improbable and electrifying as any Brazilian telenovela –although infinitely more consequential for the future of one of the world’s largest and most diverse democracies – Bolsonaro secured 46.93% of votes - with 94% of all votes counted.
The second-placed candidate, the leftist Workers’ party Fernando Haddad, won 28% of the vote, according to Brazil’s superior electoral court, the TSE. Behind him came the Democratic Labor party’s Ciro Gomes with 12.5%.
Those results mean Bolsonaro, who received more than 46 million votes, and Haddad will face off for the presidency on 28 October in a second round vote.
“The next few weeks are just going to be crazy … the country is just going to divide even more,” predicted Monica de Bolle, the director of Latin American Studies at Johns Hopkins University.
“It’s going to be a horrible campaign in the second round. It’s going to be one side smearing the other. Bolsonaro is going to be coming out with all the dirt on the PT [Workers’ party] – and there’s plenty of that. And the PT is going to be coming out with a lot of dirt on Bolsonaro – and there’s plenty of that too.”
Jubilant Bolsonaro followers gathered outside his beach-side home in western Rio de Janeiro on Sunday evening to celebrate the result with fireworks and barbecue.
Many of those present wore T-shirts emblazoned with Bolsonaro’s image and the slogan “É melhor Jair acostumando!” – a play on the politician’s name that roughly translates as: “You’d Bolso get used to it!”
“Jair Bolsonaro is hope for the Brazilian people,” said Jean Sartorial, a 33-year-old banker who had come to the party in a blue Brazil football jersey.
“Bolsonaro is a legend,” agreed Thiago Xavier, a 30-year-old estate agent.
There was frustration and defiance as it began to sink in that Bolsonaro would fall just short of a first round victory.
“Damn, 48%!” said Washington Silva, 66, a retired air force colonel. “The second round will be fiercer,” Silva added. “More aggression.”
Brian Winter, the editor-in-chief of Americas Quarterly, said the colossal support for Bolsonaro in much of the country meant he was now a huge favourite to beat Haddad.
“The path for Haddad to close that gap looks almost impossible,” he said. “This idea that Bolsonaro can save the country and make it safe for people to walk on the streets at night and tend the corruption in Brasilia and make a dent in 13m unemployed – that’s an idea most Brazilians now seem to have bought.”
In a broadcast on the eve of the election, the 63-year-old candidate of the Social Liberal party echoed Donald Trump with a call to his 7 million Facebook followers: “Let’s make Brazil great! Let’s be proud of our homeland once again!”
Throughout his 27-year career as a congressman, Bolsonaro has been notorious for throwing vitriol at Brazil’s black, gay and indigenous communities, as well as his support for military rule.
“Yes, I’m in favor of a dictatorship! We will never resolve grave national problems with this irresponsible democracy,” the politician, who has been described as a blend of Hugo Chávez and Chilean dictator Augusto Pinochet, told Congress in 1993.
In a 2015 interview Bolsonaro defended Brazil’s 1964-85 dictatorship – responsible for killing and disappearing hundreds of opponents - as a benevolent but essential means of preventing “the ‘communisation’ of our country.”
“You had complete freedom to come and go and do whatever you wanted to do in our country [back then] … It was an era of employment, security, respect, education,” he claimed.
Last month Bolsonaro called for his left-wing political opponents to be shot; two days later he himself was stabbed in an attempted assassination at a rally.
But in the final days of the campaign, the far-right front-runner, forced to campaign from a hospital bed, tried to recast himself as a paragon of tolerance who would rule for all Brazil’s 208 million citizens regardless of their skin-colour or faith.
“We will govern for everyone … even the atheists,” he insisted in one pre-election broadcast. “Let’s change Brazil together.”
KUDLOW: TRUMP THINKS RELATIONSHIP WITH CHINA IS BROKEN
TRUMP TRADE POLICY HAS PUT THE CHINESE ON NOTICE
CHINESE `SO-CALLED FRIENDS' HAVE DONE LOTS OF MISCHIEF
@zerohedge
Afghan officials have signed contracts for two major mining projects in northern Afghanistan, pushing ahead with plans to develop the country’s mineral reserves but drawing criticism over the involvement of a former minister in the project.
The deals were signed in Washington on Friday with mining and investment group Centar and its operating company Afghan Gold and Minerals Co to develop two sites in Badakhshan and Sar-e Pul provinces with potentially major gold and copper deposits.
The deals, reviving projects that have been stalled for years, follow a push by U.S. and Afghan authorities to develop mineral resources estimated to be worth some $1 trillion and seen as vital to building a functioning economy in Afghanistan after four decades of war.
“This investment will be transformative for Afghanistan,” Sadat Naderi, Chairman and President of Afghanistan Gold and Minerals, said in a statement.
“Once we begin mining, the country will benefit from major investments in infrastructure as well as fiscal revenue from our projects,” he said.
Poor security, rampant corruption and a lack of roads, power and other infrastructure, have hampered development of Afghanistan’s mining sector. The few major deals which have been signed, including the vast Mes Aynak copper project signed with China’s state-run China Metallurgical Group Corp, have so far remained largely inactive.
‘WORRYING SIGNAL’
The involvement of Naderi, who served as urban development minister until June this year, has been criticized by campaigners including Integrity Watch Afghanistan, which said it was a “clear breach” of rules barring former ministers from holding concessions after leaving office.
Under Afghan law, ministers may not hold mining contracts for five years after leaving office.
Ikram Afzali, Executive Director of Integrity Watch Afghanistan and a member of the Mining Watch Afghanistan civil society group, said it would send a “very worrying signal” if some of the first major mining contracts it signed had question marks over them.
A spokesman for the ministry of mining in Kabul rejected the criticisms, saying the deal was approved in 2012, before Naderi became a minister, and had been thoroughly vetted and approved.
“These contracts have passed through all legal stages, there is no legal issue. We reject all criticism,” the spokesman said.
Centar also said the bidding project “followed a transparent, standards-based and competitive bidding process supported by international transaction and transparency advisers”.
The copper project in Balkhab district in Sar-e Pul is an early stage exploration project covering 500 square km, with development due to begin in early 2019, Centar said. A spokesman for the ministry of mining in Kabul said the contract would run for 30 years and involve $56 million investment.
The second project, a gold mining operation in Badakhshan in northeastern Afghanistan, will explore and develop an area with known gold deposits that have long been exploited by artisanal miners. Exploration is due to begin next year.
A ministry spokesman in Kabul said the project would also run for 30 years and involve investment of $22 million.
A new standard related to steel air pollutants and coking chemical materials will go into effect in North China's Hebei province at the beginning of next year, according to Hebei authorities recently.
The emission restrictions on coal-made pellet smoking gas will be much more stringent than the current national standard, which also reached the strictest level of the country's standard, the Hebei environmental and quality supervision authorities said on September 30.
The new emission standard is also the first national coking chemical standard in the country that strengthens the control of coking particles, with the lowest emission restriction at 10 milligrams per cubic meter.
Companies in the industries will follow those rules starting October 1, 2020, and the newly established firms will follow the regulations since January 1, 2019.
According to a three-year action plan released by the provincial government at the end of August, steel companies in Hebei province satisfying the standard of renovation will achieve the lowest emission standard by 2020.
By October 2020, the coking industry in Hebei will complete advanced treatment to achieve the lowest emission standard.
There are 359 steel projects in the province that need to be improved in three years, said Li Hongyan, deputy director of the technology department at the Hebei Provincial Environmental Protection Department.
Of these projects, 83 have entered the beginning stage with 171 under construction, Li said.
China's finance minister said the country will adopt a more proactive fiscal policy but will not resort to a deluge of strong stimulus policies.
Minister of Finance Liu Kun said the fiscal policy should be more forward-looking, flexible and effective to play a bigger role in boosting demand, restructuring the economy and promoting high-quality development.
In an interview with Xinhua, Liu said the proactive fiscal policy will prioritize four sectors, namely cutting taxes and fees, improving weak links, boosting consumption and improving people's livelihood.
Apart from policies to reduce taxes and fees unveiled at the beginning of the year, China has announced more policies to support the real economy and technological innovation, which will help reduce enterprises' burden by more than 1.3 trillion yuan (about 188.4 billion U.S. dollars) this year, Liu said.
He said the ministry is working on more measures to cut taxes and fees, which if implemented, will make the growth of fiscal revenue stay at a low level in the coming months.
The country's fiscal revenue rose 4 percent year on year to 1.11 trillion yuan in August, slowing from the 6.1-percent gain in July.
With the economy on firm footing and fiscal revenue increasing, China lowered its fiscal deficit target for 2018 to 2.6 percent of GDP, down by 0.4 percentage points compared with 2017.
STARKVILLE, Miss.—Over the past hundred years, the George family’s farm has been sharecropped, grazed by cattle and planted with cotton. By the late 1980s, Clayton George was growing soybeans and struggling to make ends meet.
A new federal program offered farmers money to reforest depleted land. Pine trees appealed to Mr. George. He bought loblolly seedlings and pulled his pickup into a parking lot where hands-for-hire congregated.
“We figured we’d plant trees and come back and harvest it in 30 years and in the meantime go into town to make a living doing something else,” he said.
Three decades later the trees are ready to cut, and Mr. George is learning how many other Southerners had the same idea.
A glut of timber has piled up in the Southeast. There are far more ready-to-cut trees than the region’s mills can saw or pulp. The surfeit has crushed timber prices in Mississippi, Alabama and several other states.
By Jamie Workman, Environmental Defense Fund |
Back in 1981, President Ronald Reagan caused an uproar when he warned that trees "cause more pollution than automobiles do." Go ahead, snicker. I sure did. But recently I discovered that he was actually right (albeit for all the wrong reasons).
Today, our Western forests — from the Rockies to the mountains of the Sierra Nevada — are loaded with several billion excess trees. This is the unintended consequence of a longstanding federal policy, symbolized by Smokey Bear, to stamp out forest fires.
That policy has radically altered our forest landscapes, where fires set by lightning or Native Americans had always limited forest stocks to roughly a few dozen trees per acre. All that changed in 1910, when a series of huge wildfires led the federal government to declare war on wildfires through a program that now costs more than $2 billion a year. [In Photos: Devastating Colorado Wildfires]
The result: roughly 112 to 172 more trees per acre in mountain forests of the West. This process of unnatural afforestation (the establishment of trees or tree stands where none previously were) may sound green and benevolent, but the reality is quite different.
The new trees' canopies collectively intercept 20 to 30 percent of snow and rain that can no longer seep into the ground, and each additional tree's roots suck 18 gallons of moisture up out of the ground before runoff can feed thirsty creeks.
That adds up. Helen Poulos, a fire ecologist at Wesleyan University, and I have estimated, conservatively, that excess trees in the 7.5 million acres of Sierra Nevada conifer forest are responsible for the loss of more than 15 billion gallons per day, or 17 million acre-feet of water per year. That's more than enough water to meet the needs of every Californian for a year.
Chinese authorities mulled starting winter cuts om heavy industry production across the Yangtze River Delta region from November, according to the most recent draft for public comments.
Policymakers aim to reduce average concentrations of fine particulate matter by around 5% on a yearly basis during October 1, 2018 to March 31, 2019. They also expect to reduce the numbers of extremely polluted days by some 5% year on year.
Concentrations of fine particulate matter in nine cities, including Xuzhou in the nation’s second biggest steelmaking province, across the region exceeded 70 micrograms per cubic metre in last year’s winter. This drew the attention of authorities, who stepped up curbs this year.
Production curbs, effective from November 2018 to February 2019, will also apply to building material, coke, casting, nonferrous and chemical sectors.
The draft discouraged the use of blanket cuts and that there would be more exemptions to winter curbs for mills who have upgraded facilities. Cities or provinces are required to set their own detailed plans for curbing production, by the end of October.
China's state-owned enterprises (SOEs) will continue efforts to resolve industrial overcapacity across the steel, coal and coal-powered sectors, according to minutes from the meeting on reforming SOEs held by the central government on Tuesday October 9.
The meeting emphasized the importance of supply-side structural reform. SOEs are required to speed up structural adjustment and upgrading, step up efforts in innovation and accelerate the development of quality facilities. This is in addition to deleveraging, reducing costs and lowering financial risks.
Reforming mixed-ownership policies, developing market-driven operational mechanisms, renovating authorised operation of state capital and intensifying the supervision of state-owned assets were also proposed at the meeting.
He is expected to meet with a group of senior princes the king tomorrow (led by Khaled al-Faisal) to discuss him in the Khashoggi dilemma. All of them know that the king is gone and that his son is the owner of power. They know that the solution is not in his interview, but in an open collective position, but they are idiots and cowards who move like a child who complains to his grandfather about his brothers
The incident has preoccupied the whole ruling family, but their feelings varied between the pessimism of Ibn Salman and the joy of his divorce and the concern about their fate because they are unable to deal with the consequences. Very few of them discussed the practical solutions of adopting alternative leadership and meeting them and exploiting the event to get rid of Salman and his son
Google translate
@mujtahidd
In what the company calls an industry breakthrough, Arizona based Urbix Resources has produced the first economically viable graphene-enhanced lightweight concrete.
Urbix’s research and development team created what they call a ‘Graphenesque’ additive that provides a 33% increase in compressive strength, a 32% reduction in CO2 emissions, and at a cost that is over 16% lower than the next best lightweight concrete alternative on the market.
“As the world continues to apply IOT-enabled smart materials, we are creating and opening new market potentials for graphite, directly, positively, impacting graphite demand in the world,” Cuevas said.
The team has been working on the project since 2014, with the simple intent of commercializing graphite out of a mine in Mexico, Urbix Chairman Nicolas Cuevas told Mining.com. With carbon atoms 200 times stronger than steel, it’s pretty much the plastic of now, Cuevas said. It’s pretty much a new revolution in materials
Urbix worked with the University of Arizona’s optical science department on methods of purifying graphite without using high temperature ovens or hydrofluoric acid. Through a trial and error purification process, they were able to make graphene through a microwave reactor the company developed.
Cuevas said graphene is a ‘wonder material’, derived from graphite. Defined as a layer of carbon atoms, global demand for graphene is expected to increase as it has been shown to improve battery technologies.
“With carbon atoms 200 times stronger than steel, it’s pretty much the plastic of now,” Cuevas said. “It’s pretty much a new revolution in materials.”
“The material performance of our solution for lightweight concrete is great,” Urbix Chief Marketing Officer Adam Small said in a statement. “But the low costs and large-scale capabilities are what makes this achievement so profound. By leveraging our existing global graphite mining relationships, we offer near vertical integration, an aspect that is almost mandatory for any company entering the graphene space.”
Testing continues, and Cuevas anticipates that they will bring the technology to market in 2020.
http://www.mining.com/big-graphene-industry-breakthrough-arizona/
Venezuela’s September crude sales to the United States rose
Venezuela’s September crude sales to the United States rose to their highest in over a year, boosted by purchases by Citgo Petroleum, and Valero Energy, according to Refinitiv Eikon trade flows data.
@baryal111
Indian buyers reduced U.S. crude purchases and loaded up on Iranian oil ahead of the restart of U.S. sanctions next month and as the WTI-Brent differential narrowed, according to traders and shipping intelligence firm Kpler.
U.S. oil shipments to India fell to 84,000 barrels per day (bpd) last month, down 75 percent from a record high of 347,000 bpd in June, Kpler data showed. India accounted for 12 percent of U.S. crude exports in June.
Last month, Indian buyers lifted purchases of Iranian crude to 502,000 bpd, up 111,000 bpd over August, in “a last gasp” of purchases “before sanctions actually hit,” a U.S.-based trader said, adding that those additional barrels displaced U.S. crude.
Overall U.S. exports also fell 917,000 bpd to 1.7 million bpd in the last week of September, according to the Energy Information Administration, as a stronger U.S. dollar and Brent’s premium to WTI fell, making U.S. crude less affordable.
India, which has become a key Asian destination for U.S. crude this year, has been one of the top two buyers of Iranian crude. However, the country’s refiners since June have cut purchases of Iranian crude ahead of U.S. sanctions.
U.S. exports to all Asian countries fell 73,000 bpd to 427,000 bpd last week, while U.S. shipments to Europe dropped 102,000 bpd to 543,000 bpd, Kpler data showed.
Iran’s crude exports to China also increased by 29,000 bpd to 620,000 bpd, according to Kpler, as China cut its U.S. purchases amid an ongoing trade spat with the United States.
As U.S. sanctions on Iran have forced some countries to stop importing oil from Iran, crude oil prices have inevitably risen. The U.S. started down this path earlier this year when President Trump announced the withdrawal from the Obama-era Iran nuclear agreement.
Some sanctions went into effect in August, but the sanctions with potentially the most significant global implications go into effect in November, when the sanctions target Iran’s oil exports.
In May of this year, Iran exported 2.7 million barrels of oil per day, which accounted for nearly 3% of the world’s daily crude oil consumption. The new sanctions are expected to impact about 1.5 million BPD of Iran’s exports.
Under pressure from the U.S., many countries have begun to reduce oil exports from Iran. As the market has slowly absorbed the implications of this loss, crude oil prices have steadily risen. As recently as August, a barrel of Brent crude oil was still in the upper $60s. Today, the price has risen to $83/bbl — a four-year high. West Texas Intermediate is now over $73/bbl.
This was entirely predictable. The world simply does not currently have a lot of spare crude oil capacity. But there is a widespread belief that the Organization of the Petroleum Exporting Countries (OPEC) has excess capacity that can be used to offset the loss of Iranian oil.
In fact, President Trump has tweeted his ire at OPEC on several occasions, most recently on September 20th when he wrote:
We protect the countries of the Middle East, they would not be safe for very long without us, and yet they continue to push for higher and higher oil prices! We will remember. The OPEC monopoly must get prices down now!Related: What Drove Brent Above $85?
Saudi Arabia claims about 1.5 million BPD of spare capacity but that would take their production to an all-time high. A number of people have asked if I believe their claim. Yes, I think they do have some excess capacity, but the bulk of that is reserved for true emergencies. High oil prices do not constitute an emergency.
A true emergency would be the outbreak of violence in a major oil-producing country that took millions of barrels offline. In other words, a sudden, unexpected event that rocks that oil markets.
Publicly, Saudi Arabia and Russia rebuffed President Trump’s request. Saudi Energy Minister Khalid al-Falih stated “The markets are adequately supplied. I don’t know of any refiner in the world who is looking for oil and is not able to get it.”
Privately, Saudi Arabia is expected to increase production somewhat to offset Iran’s lost barrels. It won’t be enough to make up for all of Iran’s lost exports, and it will put the world in a more precarious situation in case of a real emergency. But it may be enough to stave off a quick return to $100/bbl, as some analysts are predicting.
https://oilprice.com/Energy/Crude-Oil/Is-The-Threat-Of-High-Oil-Prices-Overstated.html
Baker Hughes Friday reported that the number of active U.S. rigs drilling for oil fell by 2 to 861 this week. The oil-rig count had edged down by 3 last week.
The total active U.S. rig count, which includes oil and natural-gas rigs, was also lower by 2 at 1,052, according to Baker Hughes.
Washington said it may grant waivers to sanctions against Iran’s oil exports next month, and as Saudi Arabia was said to be replacing any potential shortfall from Iran.
U.S. sanctions will target Iran’s crude oil exports from Nov. 4, and Washington has been putting pressure on governments and companies worldwide to cut their imports to zero.
However, a U.S. government official said on Friday that the country could consider exemptions for nations that have already shown efforts to reduce their imports of Iranian oil.
In a sign that Iran oil exports won’t fall to nothing from November, India will buy 9 million barrels of Iranian crude next month, Reuters reported on Friday.
Further weighing on oil prices was “chatter that Saudi Arabia has replaced all of Iran’s lost oil”, said Stephen Innes, head of trading for Asia-Pacific at futures brokerage Oanda in Singapore.
But Innes warned that limited spare production to deal with further supply disruptions meant “the capacity is quickly declining due to Asia’s insatiable demand”.
India will buy 9 million barrels of Iranian oil in November, an industry source told Reuters, indicating that the world’s third biggest oil importer would continue to buy crude from the Islamic republic despite U.S. sanctions coming into force on Nov. 4.
Indian Oil Corp will lift 6 million barrels of Iranian oil and Mangalore Refinery and Petrochemicals Ltd 3 million barrels, the source with the knowledge of the matter said.
The United States has said it plans to impose new sanctions targeting Iran’s oil sector on Nov. 4 with the aim of stopping the country’s involvement in conflicts in Syria and Iraq, and bringing the Islamic Republic to the negotiating table for its ballistic missile program.
CANADA CRUDE OIL EXPORTS TO THE UNITED STATES ROSE 210,000 BPD TO 3.54 MLN BPD IN AUG (VS 3.33 MLN BPD IN JULY): STATISTICS CANADA.
@Lee_Saks
Investors still haven’t forgiven oil companies for being ill-prepared for a crude-price collapse four years ago. Perhaps more than half a trillion dollars will change their minds.
With oil above $80 a barrel as costs languish at an eight-year low, the industry is seeing green. In 2018 alone, it will rake in as much extra money as it did in the previous five years combined, according to consultant Rystad Energy AS. You could liquidate Facebook Inc. and it wouldn’t touch what oil companies will generate in free-flowing cash over the next three years.
They may need every dollar. So far nothing oil companies have done -- from $25 billion buyback programs to better earnings than in the days of $115 oil -- has gotten them out of the doghouse with investors. Share-prices increases have fallen well behind the surge in crude. while in the U.S., oil companies haven’t kept up with broader index gains at all.
“The comeback in free cash flows has only gradually started to be visible,” said Espen Erlingsen, a partner at Rystad, by email. Investors are probably “waiting to see how these oil companies will spend the extra money.”
Free cash flow at international oil companies is expected to more than double this year, to a record $175 billion. Then it will rise again in 2019, to close to $200 billion, and stay around that level for at least two years after that, according to Rystad Energy.
The estimate comes with a big caveat. Oil prices can’t fall from today’s level of more than $80 a barrel, and companies can’t return to pre-crash spending heights.
There are reasons to doubt the sustainability of crude’s rally. Oil prices have surged in the past year, in part because a snap-back of U.S. sanctions on Iranian fuel exports is driving fears of supply shortages. BP Plc Chief Executive Bob Dudley said those concerns could subside by the end of the year and that prices “feel high.”
Investors are also uncertain whether they can trust oil company executives to exercise restraint as crude keeps soaring. Firms committed to increasingly large projects from 2008, buoyed by a bullish crude market. By 2014, when prices collapsed, costs and investments for international oil companies rose to $560 billion, while free cash flow fell to less than $50 billion, not enough to cover dividend payments, Rystad data show.
While the same companies cleaned up their balance sheets and are now more profitable than before the crash, investor confidence in the sector hasn’t been fully restored. The S&P 500 Energy Index has gained about 7 percent so far this year, lagging the S&P 500’s 8 percent rise. Crude oil traded in the U.S. has jumped 22 percent over the same time period.
“The concern of some investors is that capital discipline isn’t really here to stay,” said Jason Gammel, an analyst at Jefferies LLC. “We’re not that far into the recovery yet.”
Executives will have the chance to make their case this week at the Oil & Money conference in London, which kicks off Tuesday.
Investors have heard austerity pledges after previous down cycles in the oil price, only to abandon the idea when crude shot back up, said Gammel. The big cash flow figures would have to actually materialize, accompanied by sustained efforts to return extra money to shareholders, to win back trust.
Purchase to restart stalled exploration effort next year as majors increase exposure to war-torn country
Eni has agreed to acquire a controlling stake in BP’s assets in Libya and plans to resume oil exploration there, the Italian energy giant said Monday.
The company will join a handful of others betting on prospects in the war-torn nation. Some companies are investing in Libya because “oil prices are high and the political situation is reasonably stable,” said Jason Pack, president of U.S.-based consultancy Libya Analysis. “That means more oil will come out.”
Insecurity had forced BP to suspend searches for oil and gas as part of three $900-million projects four years ago.
The country descended into chaos following a 2011 civil war that toppled dictator Moammar Gadhafi. Last month gunmen carried out a deadly attack on the offices of Libya’s state-run company National Oil Corp., an incident for which the radical Islamic State later claimed responsibility.
But in recent months, NOC has also negotiated a return to operations in fields and ports formerly blocked by militias, boosting its output by up to roughly 1 million barrels a day. That has led to renewed appetite for its oil concessions.
Eni said it has signed a letter of intent to acquire a 42.5% stake in the assets held by the U.K.’s BP PLC, the companies said in a press release. The share purchase will give the Italian major operatorship of the projects, where it intends to restart exploration next year, they said, without providing details on the terms of the deal.
“This agreement is a clear signal and recognition by the market of the opportunities Libya has to offer and will only serve to strengthen our production outlook,” NOC Chairman Mustafa Sanalla said. “This initiative will hopefully drive further inward investment and facilitate higher production levels.”
Last week, NOC said Russia’s state-controlled Tatneft had agreed to return to Libya seven years after suspending operations. The Libyan company also has held discussions with Gazprom , Russia’s largest government-owned company, to reactivate a giant gas project in Libya.
The asset transfers reflected oil companies’ unequal situations, said Mr. Pack, who frequently advises firms operating in Libya. Those in Southern and Eastern Europe are backed by their governments and have less stringent safety and security constraints, unlike their peers in the U.K. and the U.S., he said.
In March, Total SA bought a 16.33% stake of an East Libyan concession from Marathon Oil Corp. for $450 million, though the French company remains embroiled in a dispute with NOC over the purchase.
Russia could extend the timeline for its oil production growth by at least five to seven years and attract “several hundred billion rubles” in additional investment into its oil industry each year if it adopts a range of incentives for the sector, Deputy Energy Minister Pavel Sorokin told the TASS news agency on Monday.
Russia’s finance and energy ministries are currently discussing how to incentivize the country’s oil industry amid expectations that current fields and regions with benefits will exhaust their growth potential as early as in 2022-2023.
Production growth coming to a halt around that time “will entail an extremely adverse impact on investments with the multiplication effect and will result in dramatic reduction of budget revenues. Therefore, preventive measures should be undertaken,” Sorokin told TASS.
Around 60 percent of Russia’s oil reserves are in West Siberia, Sorokin told TASS, noting that half of those reserves would not be developed under the current fiscal system for Russia’s oil industry.
Last month, Russia’s Energy Minister Alexander Novak was quoted as saying that Russia’s oil production could peak as early as in 2021 due to high taxes and costs, provided there are no benefits for exploration or tax incentives introduced.
Russia’s oil production is expected to average around 553 million tons this year, or 11.105 million bpd, Interfax news agency quoted Novak as saying at a government meeting on incentives to boost Russia’s oil industry.
By 2021, Russia’s oil production will rise to 570 million tons, which, without more benefits and lower taxes, could be the peak oil production, Novak warned.
If current production trends continue, and if Russia doesn’t do anything to further stimulate oil exploration and new field development, after 2021, production may start to fall and reach just 310 million tons by 2035, that is, Russia’s oil production could drop by 44 percent by then, Novak said, as quoted by Interfax.
Exploration and new oil field development are becoming increasingly important for Russia’s oil industry, Prime Minister Dmitry Medvedev said at the meeting, adding that the government needs to first assess reserves, draft measures for the incentives mechanism, and review the current benefit system.
A vessel carrying 2 million barrels of Iranian oil discharged the crude into a bonded storage tank at the port of Dalian in northeast China on Monday, according to Refinitiv Eikon data and a shipping agent with knowledge of the matter.
Iran, the third-largest producer in the Organization of Petroleum Exporting Countries (OPEC), is finding fewer takers for its crude ahead of U.S. sanctions on its oil exports that will go into effect on Nov. 4. The country previously held oil in storage at Dalian during the last round of sanctions in 2014 that was later sold to buyers in South Korea and India.
The very large crude carrier Dune, operated by National Iranian Tanker Co, offloaded oil into a bonded storage site at the Xingang section of the port, according to a shipping source based in Dalian, adding this was the first Iranian oil to discharge into bonded storage in nearly four years.
The tanker left the Iranian oil port at Kharg Island on Sept. 12, according to ship-tracking data.
The Xingang area is home to several tank farms including commercial and strategic reserves. China National Petroleum Corp (CNPC) [CNPC.UL] and Dalian Port PDA Co Ltd (601880.SS) both operate commercial storage in the area, according to information on their company websites.
An investor relations official at Dalian Port declined to comment.
A manager at the bonded crude storage site operated by Dalian Port declined to comment whether Iranian oil were moved to the tanks, calling it the “worst time” to give any comment regarding Iranian crude because of the U.S. sanctions.
A person at the CNPC-owned storage site who refused to identify himself when contacted by Reuters said it is “impossible” that the oil is stored there.
A spokesman for CNPC said he had no information on this matter.
An executive with the China office of National Iranian Oil Co (NIOC) declined to comment. NIOC also did not respond to an email request seeking comment if it is storing oil at Dalian.
The shipping source said there is no buyer earmarked for the cargo.
Three other NITC tankers are set to arrive in Dalian in the next week or two, the ship-tracking data shows. Some of those cargoes are also likely to end up in bonded storage as the refineries in the region, controlled by CNPC, are not equipped to process Iranian oil, said three sources at state-run Chinese refiners.
China’s Iranian oil buyers, including state-owned refiner Sinopec (0386.HK) and state trader Zhuhai Zhenrong Corp, have shifted their cargoes to vessels owned by NITC since July to keep supplies flowing as the U.S. sanctions have been re-imposed.
Keeping oil in bonded storage gives the shipment owner the option to sell into China or to other buyers in the region.
In early 2014, NIOC leased bonded tanks in Dalian and oil from there was shipped to South Korea and India, Reuters reported.
U.S. crude oil exports are expected to hit nearly 4 million barrels a day by 2020.
The export volumes are expected to rise to 2.2 million barrels a day in 2019 and hit 3.9 million barrels a day by 2020, according to a new report by research firm S&P Global Platts.
The increasing crude oil exports will be linked to continued oil production growth in U.S. shale oil fields, particularly the Permian Basin in West Texas, which is currently producing around 3.4 million barrels of oil a day.
The report estimates that the Permian -- which stretches from West Texas into New Mexico -- accounted for more than a quarter of U.S. oil production in 2017.
The S&P report said current ship borne export capacity out of the U.S. is around 4.8 million barrels per day, with Texas accounting for the vast majority of the total, 3.9 million barrels a day. Houston is said to have the lions share of export capacity -- more than 2 million barrels a day -- while the Corpus Christi and Brownsville region has more than 1.1 million barrels a day of oil export capacity.
Iran’s Oil Exports May Be More Resilient Than Headlines Suggest
Iran is resorting to “Houdini tricks” to sustain oil exports as US sanctions loom. New data suggests the magic might be working. With new sleights of hand including disappearing oil tankers, the use floating storage, and ship-to-ship transfers, tracking Iranian exports is getting harder than ever, leading to divergent estimates from oil analysts.
While S&P Global Platts has reported Iran’s September exports at about 1.7 million bpd, marking an 11 percent decline from August, data from TankerTrackers, a service which reports shipments and storage of crude oil globally, puts the export volume at just over 2 million bpd. The divergence in the datasets represents not merely 300,000 bpd, but also the difference between two narratives about the state of Iran’s exports in the face of returning US sanctions.
As part of S&P Global Platts’ announcement of the September figures, Paul Sheldon, chief geopolitical adviser at company, stated, "Iranian export losses have already accelerated faster than we expected.” On this basis, Platts is predicting Iran’s exports will fall to 1.1 million bpd by November, when U.S. sanctions on Iran’s oil industry are set to return. Similar analysis from Bloomberg and Reuters has contributed to the sense that Iran’s exports are dropping fast. But these assessments may be leaving a significant number of barrels uncounted by failing to properly capture tankers which have turned off their geolocation transponders.
Samir Madani, founder of TankerTrackers, emphasizes that such tactics are making life more difficult for those trying to measure Iran’s export volumes. "September was a very resource-demanding month from a vessel tracking perspective for not just us at TankerTrackers but at some of the other trackers in the industry,” he said.
TankerTrackers (bpd) S&P Global Platts (bpd)
China
623k 443k
India
499k 357k
Unidentified
200k 272k
UAE
150k 71k
Turkey
141k 139k
Italy
137k 138k
Spain
103k 103k
Japan
46k 42k
Greece
36k 34k
Syria
36k 0
Croatia
35k 33k
South Korea
0 65k
Chart: Bourse & Bazaar Source: TankerTrackers.com, S&P Global Platts Get the data Created with Datawrapper
For Madani and his team, properly tracking tankers laden with Iranian oil requires extensive use of satellite imagery. “The reason is because roughly half of the exports were cloaked, meaning vessel crews switched off their AIS geolocation transponders before arriving into Iran to arrange the collection of crude oil,” Samir explained. “Their transponders were switched back on many days later, once they were already out of the immediate Gulf area.”
To overcome these cloaking tactics, Madani uses daily satellite imagery to “factor in vessels that were no longer broadcasting their positions.” This methods helps explain the significant discrepancy between his September estimate of Iran’s exports to China and that published by Platts. According to Madani, Iran’s state-owned National Iranian Tanker Company is particularly adept at cloaking exports in this manner, drawing on a playbook perfected in the previous sanctions period.
Any underlying resilience of Iranian exports is particularly important following reports that the United States is “actively considering waivers on Iran oil sanctions.” The exploration of waivers represents a break with the Trump administration’s previously communicated intention that “exports of Iranian oil and gas and condensates drops to zero.”
The level of imports covered by such “significant reduction exemptions” or SREs is typically determined by looking to historical import levels and the level of imports that can be reasonably restricted by sanctions. In this context, that Iran has been able possibly sustain over 2 million bpd in exports just one month before the reimposition of US sanctions bodes well for the extent of the waivers that may be offered. In likely anticipation of waivers from US authorities, India has already announced that it plans to import at least 9 million barrels of Iranian crude in November.
In an interview conducted during the United Nations General Assembly, President Hassan Rouhani told NBC’s Lester Holt that “The United States is not capable of bringing our oil exports to zero” and describe the Trump’s administration's threats as “empty of credibility.” Despite hopeful signs, Iran’s oil exports magic show is still in its first act. Whether Rouhani can outdo the great Houdini is yet to be seen.
https://www.bourseandbazaar.com/articles/2018/10/8/irans-oil-exports-may-be-more-resilient-than-headlines-suggest
EUROPEAN GASOLINE STOCKS AT 109.48 MLN BARRELS IN SEPT, DOWN 0.3 PCT FROM AUG, UP 1 PCT Y/Y: EUROILSTOCK.
EUROPEAN CRUDE OIL STOCKS AT 474.28 MLN BARRELS IN SEPT, DOWN 1.4 PCT FROM AUG, UP 1.3 PCT Y/Y: EUROILSTOCK.
@Lee_Sak
Oil is flowing from a drill site in what is now the farthest-west producing site on Alaska’s North Slope, ConocoPhillips Alaska Inc said on Tuesday.
Production at Greater Mooses Tooth 1, a prospect on the western edge of existing Arctic Alaska oil development, started last Friday, ConocoPhillips said.
Production at GMT 1 is expected to peak at 25,000 to 30,000 barrels a day, the company said. It is the second producing oil field within the borders of the National Petroleum Reserve in Alaska, or NPR-A, a vast federal land unit on the western side of the North Slope.
“This is another milestone for development in the NPR-A,” Joe Marushack, president of ConocoPhillips Alaska, said in a statement.
Oil from GMT 1 is being sent by pipeline east for processing at the ConocoPhillips-operated Alpine field. That oil is then shipped by pipeline to Prudhoe Bay about 50 miles to the east, then south through the Trans Alaska Pipeline System.
The first field to begin producing within the reserve boundaries was a ConocoPhillips field called CD5, where startup occurred in 2015.
ConocoPhillips is seeking to develop a related drill site about 8 miles (13 km) to the southwest of GMT1 that could start production by 2021. Peak production at that site, Greater Mooses Tooth 2, would be 35,000 to 40,000 barrels a day, according to ConocoPhillips.
Enterprise Products Partners LP’s Seaway crude pipeline will not achieve a targeted increase in capacity to 950,000 barrels per day because of issues unrelated to the expansion, the company said on Tuesday.
Enterprise and its joint venture partner, Canadian pipeline operator Enbridge Inc, originally expected to begin taking an additional 100,000 bpd in September. In recent days, it began adding a friction-reducing agent to increase the potential capacity of the 760-mile (1223 km) pipeline.
However, the September target date has been delayed due to what was described as third-party issues unrelated to the capacity expansion, Enterprise spokesman Rick Rainey said. He declined to provide further details.
The crude production surge in the Permian basin of West Texas and New Mexico, the biggest oilpatch in the United States, has outpaced the region’s pipeline capacity, causing bottlenecks and depressing prices in the region. Enterprise and others are building new or expanding existing lines to soak up the new production.
The existing Seaway system was expanded several years ago to carry up to 850,000 bpd from the main U.S. crude storage hub in Cushing, Oklahoma, to storage facilities and refineries along the Gulf Coast.
Lukoil's massive new discovery in southern Iraq -- part of the Russian firm's sizable growth plans in the Middle Eastern country -- will start production in 2021, the head of Iraq's regional state-run oil company said.
Aggressive exploration continues at Block 10, Dhi Qar Oil Company Director General Ali Warid said in a statement emailed to S&P Global Platts, following Lukoil's announcement earlier this year that "recoverable reserves in excess of 2.5 billion barrels of crude" from the Eridu-1 well was the biggest find in Iraq in 20 years.
"The Chinese Bohai company has started to drill the 4th well in the 10th exploration block," Warid said. "The drilling work comes along the same time of the 3D scan conducted by the (Iraqi state-run) Oil Exploration Company."
He added: "I predict that the actual production of the field will start in 2021 according to the plans made by Lukoil in coordination with the Oil Ministry."
Lukoil won Block 10 in a 2012 bidding round. It's located mostly in Dhi Qar province, west of Lukoil's 400,000 b/d West Qurna-2 project, located in the Iraqi oil capital of Basra province.
Yaroslav Okulov, the chief financial officer of Lukoil Mid East, said at a conference in Istanbul on Tuesday that Eridu was a "very promising discovery" and appraisal work was ongoing.
"I believe that once we finish the appraisal, reserves will come to life, so it will bring additional capacity for oil production," he said.
Lukoil is a significant foreign investor in Iraq's oil sector. The West Qurna-2 field, signed in 2010, has reached 400,000 b/d capacity, with an additional 50,000 b/d to 100,000 b/d expected by the end of 2019.
Ihsan Ismaael, the director general of the state-run Basra Oil Company, said at the Istanbul conference that the 800,000 b/d production plateau target might be increased by "20% because there are new opportunities to develop."
Okulov said the next phase of the project will be to drill additional wells for a water injection system to boost reservoir pressure, and "expand capacity of the oil treatment and water treatment facilities."
He said production from the Yamama reservoir at West Qurna-2 will bring another 30,000 b/d online in two years. "But basically, this is a pilot project, we aim to understand the potential of Yamama."
https://www.spglobal.com/platts/en/market-insights/latest-news/oil/101018-lukoil-to-start-production-at-iraqs-newest-massive-discovery-in-2021?utm_source=twitter&utm_medium=social&utm_term=oil&utm_content=news&utm_campaign=webed&hootpostid=0ac78f88b62c1626805fc1253df3810d
Marathon Oil Corporation may have potentially bought into a Tier 1 play on the cheap.
How Marathon Oil Corporation plans to appraise the Louisiana Austin Chalk play, an emerging opportunity.
Other players are starting to get active in the emerging play as well, which lends credence to Marathon Oil's ambitions.
Expect additional leasehold acquisition activity later on this year.
The Austin Chalk formation has increasingly been a core focus in the Eagle Ford region in South Texas (the Eagle Ford shale formation and the Austin Chalk formation are the bedrocks of oil & gas development activity in the area), but a new AC development region has entered the fold. Numerous upstream operators have acquired large leaseholds across acres thought to be productive for the Austin Chalk play in Louisiana, and energy investors should take note. Austin Chalk well economics in South Texas are clearly in the Tier 1 category, so any emerging play with a chance to replicate that success needs to be kept on your radar. For starters, take a look at Marathon Oil Corporation (NYSE:MRO), which just acquired a large position in the emerging play during the first half of 2018 on the cheap. Let’s dig in.
Overview
During the first half of 2018, Marathon Oil Corporation spent $250 million “predominantly on leasing in the emerging Austin Chalk play in Louisiana.”This gave Marathon Oil a ~240,000 net acre leasehold position in Louisiana, which is centered around Rapides, Allen, Evangeline, St. Landry, and Avoyelles parishes in Central Louisiana. Note that this position was acquired for just under $900 per net acre (for a total spend of ~$216 million), with the remaining expenditures going towards related activities.
Management expects Marathon Oil will spend an additional $100 million to $150 million during the second half of 2018 on the Louisiana Austin Chalk play. This is going towards the company’s first exploration well on that acreage, additional leasing activities, and a multi-client 3D seismic mapping survey that will cover 400 square miles of the play.
https://seekingalpha.com/article/4210608-marathon-oil-bets-big-louisianas-austin-chalk-upside
Mexico’s state-run Pemex said on Tuesday it has discovered up to 180 million barrels of crude oil in the Gulf of Mexico’s shallow waters, a find that is expected to help boost the country’s dwindling oil production.
Pemex, whose oil and gas output has been declining since 2004, said light and heavy crudes were found in seven reservoirs along the Mulach and Manik fields in the southern Gulf of Mexico, close to existing infrastructure for production and transportation.
“These are the reservoirs that will feed the country’s reserves,” said Mexican Energy Minister Pedro Joaquin Coldwell at a news conference with Pemex executives.
The discovery of proven, possible and probable reserves (3P) in Mulach and Manik follows discoveries announced by Pemex in recent years in four nearby fields. Together they will require $7 billion to $10 billion in investment, including drilling rigs, pipelines and at least one production platform.
Even amid budgetary constraints, Pemex in recent years has increased exploration efforts, with a 25 percent success rate in confirming reserves, below rates registered in previous decades, according to the firm’s exploration chief Jose Antonio Escalera.
Rising crude prices and an expanding budget now allow the company to do more to reverse the country’s falling proven reserves, which last year declined 7 percent to 8.48 billion barrels of oil equivalent.
Pemex expects new production from the Xikin, Esah, Kinbe, Koban, Mulach and Manik offshore fields to add up to 210,000 barrels per day (bpd) of crude and 350 million cubic feet per day (mmcfd) of natural gas by the second half of 2020.
Carlos Alberto Trevino Medina, Chief Executive Officer of Petroleos Mexicanos (Pemex), holds a news conference in Mexico City, Mexico October 9, 2018. REUTERS/Henry Romero
The first field to add barrels would be Xikin, discovered three years ago, where early production is expected in 2019. The Esah field would follow in the first quarter of 2020.
Mexico expects the downward trend in its oil reserves to turn positive in two years, following a constitutional energy overhaul enacted in 2013, said Joaquin Coldwell.
The new fields will also contribute relatively quickly to Pemex output in shallow waters, where the vast majority of its production originates. Pemex has recently been facing production problems at one of its main shallow-water areas, the Xanab light crude field.
“We still don’t have a specific production goal for this year. There’s an emergency plan to ease Xanab’s (output) declination,” Pemex’s CEO, Carlos Trevino Medina, said at the news conference.
Oil producers in the Permian basin and elsewhere could soon find themselves facing the oilfield equivalent of trying to walk up the down escalator.
The oil industry, and particularly the Permian, is in the midst of a boom. But analysts say new hints that maturing wells are falling well short of projections are prompting fresh worries that the industry may not be able to meet robust demand moving forward.
It’s a concern that could add new strength to an oil ally that’s been building since January, largely driven by volatile geopolitical issues. A study by Wood Mackenzie Ltd. found maturing wells in some parts of the Permian’s Wolfcamp shale were losing almost 15% of output annually five years after startup. That compares with the 5% to 10% initially modeled.
"If you were expecting a well to hit the normal 6% or 8% after five years, and you start seeing a 12% decline, this becomes more of a reserves issue than an economics issue.,” said R.T. Dukes, a director at industry consultant Wood Mackenzie Ltd. It means “you have to grow activity year over year, or it gets harder and harder to offset declines."
Globally, Wood Mackenzie has predicted annual decline rates offshore will rise to 6% from 2020, from 5% now.
The newest hints of production shortfalls in maturing wells follows a two-year price rout that put the brakes on costly offshore drilling, and a more recent push by oil-company investors for payback over growth. While U.S. shale fields have been booming, analysts are now starting to wonder if long-term U.S. projections will hold up, offsetting decisions to hold off exploration elsewhere.
Older well declines “are a topic that oil market analysts and investors are always trying to wrestle with,” Jamie Webster, a senior director for oil at the Boston Consulting Group Inc. in New York, said by telephone. “It’s hard to get a good sense of it because of a lack of good, real time data. But my sense is that they are starting to increase.”
The Permian basin “has had an amazing year, ” he added. "But it’s really started to slow down."
Growth in the Permian has, in fact, been shrinking, down almost every month this year, while declines in older wells are trending higher, according to the U.S. Energy Information Administration. In October, the organization’s data shows declines offsetting output by about 18%, compared with 4% at the start of the year.
The concerns, though, go beyond the Permian.
Perhaps the best example of declining production in older wells comes from Brazil’s Campos basin, which has been producing oil for more than 30 years. The region, which is traditionally responsible for more than 80% of the nation’s oil, has seen a 30% decline in output over just the last five years, the country’s oil regulator said last month.
In response, Petroleo Brasileiro SA, the country’s state-controlled energy company, will be redirecting investment into new drilling in the region.
"Decline rates are dramatic and there is a lot to be done," said Marcelo Castilho, at the sidelines of the Rio Oil & Gas Conference last month. But there’s more to track than just the big producers, said Boston Consulting’s Webster.
While production declines being seen in smaller countries such as Turkey and Pakistan may not have a lot of immediate impact, “as a whole, the result could be quite stunning.
Just as midstream companies are in a fierce competition to build new crude oil pipelines from the Permian to the Gulf Coast, there’s a race on to develop what would be the first Gulf Coast terminal in a generation capable of handling fully laden Very Large Crude Carriers. There’s a lot at stake. Currently, 2-MMbbl VLCCs can be filled to the brim without reverse lightering only at the Louisiana Offshore Oil Port (LOOP), and even if U.S. crude production continues to rise at a fast clip, it’s unlikely that more than another one or two high-capacity, VLCC-ready terminals would be needed over the next five years. And, assuming there’s not an overbuild situation, the project or projects that ultimately advance would be expected to be in-demand and highly utilized — VLCCs are the preferred mode of transporting crude to Asia and other far-away markets, and being able to fully load VLCCs saves the considerable cost and time associated with reverse lightering these supertankers in deep water. Today, we conclude our series on the fast-paced efforts to develop export terminals in waters deep enough to float VLCCs chock-full of oil.
This is the fifth episode in our series. In Part 1, we discussed the ongoing boom in U.S. crude oil exports, which have been rising steadily since the 40-year ban on most exports was lifted in December 2015. Crude exports averaged 590 Mb/d in 2016, 1.1 MMb/d in 2017, and more than 1.8 MMb/d so far in 2018. While 2-MMbbl VLCCs are by far the most cost-efficient way to haul crude to Asia, their very large physical dimensions restrict the number of land-based terminals they can use. A typical VLCC is about 1,100 feet long, with a beam (or width) of nearly 200 feet and a fully loaded draft of 72 feet. And even those land-based terminals that can accommodate VLCCs can only load these supertankers part-way — “reverse lightering” out in deeper, open waters is required to fill a VLCC to the brim. (LOOP — green diamond in Figure 1 — is the only facility along the Gulf Coast that can fully load a VLCC today.) We also reviewed the joint plan by Oiltanking, Enbridge and Kinder Morgan to develop a crude export terminal 30 miles off the coast of Freeport, TX (yellow diamond). In Part 2, we considered JupiterMLP’s proposal for an offshore export terminal only six miles off Brownsville (aqua diamond) — and a new long-haul pipeline from the Permian to that South Texas city. Next, in Part 3, we looked at the plan by Trafigura, the international logistics and trading company, to build a deepwater export terminal 15 miles off Corpus Christi (lavender diamond). Each of these projects also calls for the development of several million barrels of onshore storage capacity to support the regular loading of VLCCs. Tallgrass Energy’s plan to build a combination export and import terminal 1.5 miles off the coast of Venice, LA (near the mouth of the Mississippi River) was the subject of Part 4, which also discussed the company’s related plan to build new pipelines (Seahorse and Pelican) to connect the crude oil hub in Cushing (OK) to the hub in St. James (LA), a planned new terminal on the Mississippi in Plaquemines Parish (LA) and the proposed offshore terminal near Venice (orange diamond).
Today, we consider two other plans to develop new Gulf Coast terminals capable of handling fully loaded VLCCs — one of which may actually involve land-based docks. We begin with Enterprise Products Partners’ plan — first unveiled in July (2018) — to build an offshore terminal about 80 miles off the Texas coast, presumably connected to Enterprise’s extensive crude storage and pipeline infrastructure in the Houston/Texas City area. The offshore terminal (pink diamond indicates the general area) would be connected via a 42-inch-diameter pipeline, and would be capable of loading crude at a rate of 85 Mb/hour — fast enough to fill a 2-MMbbl VLCC in 24 hours. Front-end engineering and design (FEED) work and permitting on the project is already under way, and the company has indicated it expects to have permits and other approvals for the facility in hand as soon as early 2020.
Already, two VLCCs have been partially loaded with crude at the Texas City marine terminal owned by Seaway Crude Pipeline Co., a joint venture of Enterprise and Enbridge. Enterprise in June (2018) loaded 1.1 MMbbl onto the FMPC C Melody (a 2-MMbbl VLCC) at the Seaway terminal, and in July it did the same with the Eagle Victoria. In both cases, the VLCCs then received the balance of their crude via reverse lightering in the Galveston trans-shipment area (TSA) before sailing to their final destinations (look to RBN’s new Crude Voyager for additional details).
Figure 1. Offshore Crude Export Terminal Projects.
At the same time, the Port of Corpus Christi is spearheading an effort to develop what could be the Gulf Coast’s first land-based terminal capable of fully loading VLCCs. More specifically, the port is in the midst of a feasibility study to determine whether a VLCC-ready terminal could be developed on a roughly 250-acre tract the port owns on Harbor Island (brown dot in Figure 2), which is located adjacent to Port Aransas (TX) and near the beginning of the Corpus Christi Ship Channel. The ship channel is currently only 45 feet deep and plans are already well under way to deepen it to 54 feet. Under the Port of Corpus Christi’s Harbor Island development plan, the initial stretch of the ship channel from the Gulf to the channel’s La Quinta Junction (including the proposed terminal site) would be deepened to 75 to 85 feet — a depth sufficient to handle fully laden VLCCs. Still to be determined as part of the feasibility study, which will be completed late this year, is if the supertankers would pull up to a land-based dock on Harbor Island or an offshore buoy very near the island. The Harbor Island terminal could include as much as 20 MMbbl of onsite crude storage capacity, and would be connected to mainland pipes and other infrastructure via two 30-inch-diameter lines. Port officials have indicated that they do not intend to develop the terminal on their own, and instead, they envision partnering with private-sector entities. Magellan Midstream Partners has been mentioned as a possible affiliate, and Flint Hills Resources — which already has a substantial presence in Corpus Christi — may be another.
Figure 2. Port of Corpus Christi’s Harbor Island Project.
A key motivator for the Port of Corpus Christi in its development of a possible Harbor Island terminal may be the potential loss of crude oil exporting volumes through the port (and port revenue) if Trafigura were to proceed with the construction of its planned crude export terminal 15 miles off the coast of Corpus Christi (lavender diamond in Figure 2).
At the same time, a joint venture of Buckeye Partners, Phillips 66 Partners and Andeavor (now part of Marathon Petroleum) is developing the South Texas Gateway Terminal in Ingleside (red dot) see Working on a Dream). By late 2019, that new facility will offer 3.4 MMbbl of crude storage capacity (expandable to 10 MMbbl-plus), connectivity to the Phillips 66 Partners and Marathon’s planned 700-Mb/d Gray Oak Pipeline from the Permian (expandable to 1 MMb/d), and two deepwater docks. The docks initially will be capable of partially loading VLCCs, with full loading of VLCCs at the docks a possibility later on.
As we said in the intro to today’s blog, it’s unlikely that more than one or possibly two new crude terminals capable of sending out fully loaded VLCCs will be built — even with rising production in the Permian and other plays — because the volumes necessary to support multiple terminals along the Gulf Coast simply wouldn’t be there. That means that the race is on to advance the first offshore terminal to its final investment decision (FID). To win that contest, a proposal would need to offer pipeline access to large volumes of Permian and other crude, as well as favorable economics — that is, development costs (and terminal fees) low enough to convince crude exporters (producers, marketers and/or shippers) to make long-term commitments for terminal through-put capacity. In the end, project development costs need to be low enough to justify the switch from full reverse lightering (or a combination of partial loading at a dock and partial reverse lightering) to full loading of VLCCs in one place. We’ll continue to monitor this race and, given the market pressures at work, it may not be long before there’s a winner.
https://rbnenergy.com/deep-water-part-5-more-plans-for-offshore-crude-oil-export-terminals-along-the-gulf-coast
S&P Global Platts North American crude benchmark WTI's consistent discount against its Asian counterpart Platts Dubai may continue to encourage South Korean refiners to test a wide variety of US export grades, with SK Innovation receiving a cargo of White Cliffs crude oil for the very first time in the third quarter.
US-Asia crude flows have flourished ever since the North American producer had lifted a 40-year ban on crude exports in early 2016, but vast majority of the oil meeting Asian demand remains limited to export grades produced from the Permian Basin and offshore US Gulf Coast with easy access to loading terminals.
Several traders at South Korean refining companies said many of the landlocked US and Canadian crudes including Bakken, Cold Lake Blend and White Cliffs could comfortably feed into Northeast Asian distillation units, but arbitrage economics for Asian buyers had often been difficult due largely to hefty transportation and logistics costs.
However, Platts WTI crude has extended its decline against other global benchmarks Dubai and Brent in H2, further opening up the arbitrage window and making a case for South Korean refiners to at least test out some of the landlocked North American crude grades in their refinery systems.
South Korea's biggest refiner SK Innovation for one acquired 493,000 barrels of White Cliffs crude from the US in August, the company's first ever purchase of the crude produced from the Denver-Julesburg Basin, a company official told Platts Tuesday.
"DJ Common Grade Crude Petroleum shall mean Crude Petroleum with a gravity of no less than 35 degrees API and no greater than 57 degrees API," White Cliffs Pipeline stated in its rules and regulations guideline on interstate crude petroleum transportation by pipeline.
The guideline also stated that it will reject transportation tenders from the DJ Basin producers if the sulfur content of the crude exceeds 0.40%.
The White Cliffs Pipeline system consists of two 527-mile, 12-inch diameter common carrier, pipelines that move crude out of the DJ Basin to the Cushing, Oklahoma market, the pipeline operator SemGroup Corporation said on its official website. SemGroup owns 51% of White Cliffs Pipeline.
The August White Cliffs crude purchase comes on the heels of South Korea's first imports of Canadian Cold Lake Blend crude in more than two decades.
In February, GS Caltex had received 274,000 barrels of Alberta's landlocked oil, a company source previously told Platts, while about 317,000 barrels reached a South Korean port in Q2, according to Korea Customs Service.
PLATTS WTI/DUBAI DISCOUNT WIDENS
The North America-Asia arbitrage window has threatened to close in recent weeks amid a sharp spike in VLCC freight rates from the USGC to Northeast Asia, pushing up offers for WTI Midland crude delivered into the region.
Most recent trades reported for November-loading WTI Midland crude cargoes were at premiums in the low $2s/b to Platts Dated Brent on a delivered basis into Northeast Asia, Asian trade sources said.
Earlier trades for WTI Midland crude in the prior three months had been reported at premiums of $1-$1.50/b to Platts Dated Brent, Platts previously reported.
However, Asian end-users will likely continue to favor light sweet US crudes as these remain competitively priced against many North Sea, Mediterranean, West African and Middle Eastern crude grades of similar quality.
The spread between Platts front-line WTI crude swap and the same month Dubai swap tumbled to a discount of $7.83/b Tuesday, the lowest since June 8 when the discount was $8.04/b, Platts data showed.
The spread has averaged minus $5.27/b so far in H2, down sharply from minus $2.55/b in H1 and 2017's full-year average of minus $1.89/b, according to Platts data. A weaker Platts WTI versus Dubai spread typically makes North American crude grades priced against NYMEX futures calendar month average and Platts WTI more competitive than Persian Gulf and Far East Russian oil.
In addition, the front-month NYMEX/ICE Brent futures spread averaged minus $7.51/b so far in H2, compared to minus $5.71/b in H1, Platts data showed.
"Dubai and Brent have [been] much more sensitive to growing concerns about the Iranian supply cutoff after November, widening [NYMEX and Platts WTI's] relative discount," Jiwoo Shon, commodities and energy market research analyst at SK Securities, said.
Reflecting South Korean refiners' ongoing efforts to find alternative crude feedstocks to make up for the likely cutback in Iranian supply, SK Innovation has received 967,000 barrels of US Eagle Ford crude in August, the company official said.
The refiner also sharply increased crude imports from Saudi Arabia to 5.4 million barrels in August from 1.3 million barrels in July.
The extra cargoes indicate a willingness by Saudi Arabia to increase crude supply to make up the shortfall once sanctions by the United States on oil exports from Iran, the third-largest producer in the Organization of the Petroleum Exporting Countries (OPEC), start up on Nov. 4.
India is Iran’s top oil client after China, though several refiners have indicated they will stop taking Iranian barrels because of the sanctions.
Reliance Industries Ltd, Hindustan Petroleum Corp, Bharat Petroleum Corp and Mangalore Refinery Petrochemicals Ltd are seeking an additional 1 million barrels each in November from Saudi Arabia, the sources said.
Three of the companies did not immediately reply to an email from Reuters seeking comment. MRPL replied “no comments” when contacted by email.
State-owned oil producer Saudi Aramco was not immediately available for comment.
Given their dependence on Iranian oil supplies, the Indian refiners are concerned about the loss of Iranian crude once the sanctions start and are seeking exemptions. Refiners in the country have placed orders to buy 9 million barrels from Iran in November.
One of the reasons for the additional demand for Saudi oil is that the crude arbitrage from the United States is shut so the Indian buyers have to turn to Middle Eastern barrels, said one of the sources.
India, the world’s third biggest oil importer, is grappling with a combination of rising oil prices and falling local currency, which makes imports of dollar-denominated oil more expensive. Retail prices for gasoline and diesel fuel in India are at record highs and the government has cut its excise tax on fuel to ease some of the pain for consumers.
Indian Oil Minister Dharmendra Pradhan said on Monday that he spoke with Saudi Energy Minister Khalid al-Falih last week and reminded him that OPEC and other major oil producers had promised to raise their output at a meeting in June.
India imports an average of 25 million barrels per month from Saudi Arabia.
Reuters last week reported that Russia and Saudi Arabia, the world’s two biggest oil producers, struck a private deal in September to raise output to cool rising prices and had informed the United States about the decision.
The American Petroleum Institute reported that U.S. crude supplies rose 9.7 million barrels for the week ended Oct. 5, according to sources. The API data, which were released a day late due to Monday's Columbus Day holiday, also showed supplies of gasoline climbed by 3.4 million barrels, while distillates fell 3.5 million barrels, sources said.
Supply data from the Energy Information Administration will be released Thursday. Analysts polled by S&P Global Platts expect the EIA to report a climb of 1.61 million barrels in crude supplies. They also expect supply rise of 422,000 barrels in gasoline, but a decrease of 1.71 million barrels in distillates.
I'm upset.
I'm seeing headlines with lie after lie come out about Iran's September crude oil exports and production. There doesn't seem to be any self-restraint by the big media networks to carefully examine & verify everything first before spewing it out.
Completely shameful.
And for goodness sake, don't get me started on October.
@Samir_Madani
The UAE’s production capacity by year-end 2018 will be ~3.5 mbopd. Our December production will be subject to customer demand.
In line with market requirements, the UAE began to increase its oil production in Q3 and expects to further increase its production levels in October and November 2018.
@HESuhail
The U.S. Energy Information Administration on Wednesday raised its 2018 and 2019 price forecasts on West Texas Intermediate and Brent crude oil prices and U.S. production expectations for this year and next. In its monthly energy outlook report, the government agency forecast an average WTI price of $68.46 a barrel for this year, up 2.1% from the forecast issued in September. For 2019, it forecast $69.56, up 3.3%.
The EIA also raised its average Brent forecast by 2.2% to $74.43 this year, and by 1.9% to $75.06 next year. The EIA increased the domestic crude output forecast by 0.8% to 10.74 million barrels a day this year, and lifted the 2019 view by 2.2% to 11.76 million barrels a day.
https://www.marketwatch.com/story/eia-lifts-oil-price-and-us-crude-output-expectations-for-this-year-and-next-2018-10-10
A shale play that was left for dead has come roaring back in 2018.
The Bakken formation, which stretches from Montana to North Dakota, had long been considered by some in the energy industry to be played out.
Now the region is experiencing a comeback, luring investors as crude prices have surged. Oil production in North Dakota has climbed to records this year, hitting 1.27 million barrels a day in July.
That is leading to outsize gains for producers concentrated on the Bakken.
Whiting Petroleum Corp., which has operations in North Dakota, Colorado and Texas, is up 72% for the year so far. Continental Resources Inc. and Oasis Petroleum Inc. are up 24% and 57%, respectively.
“It’s interesting times in North Dakota,” said Pablo Prudencio, an analyst at energy consultancy Wood Mackenzie. “The Bakken has a story of its own right now.”
Several factors account for the Bakken’s recent rise, Mr. Prudencio said. U.S. oil futures surpassing $70 a barrel have spurred more drilling across the country. Additionally, cheaper acreage and improved crude transportation have made the area more attractive than some other major shale fields.
Namely, the Dakota Access Pipeline has made it cheaper to send crude to other parts of the country. Previously, much of the oil produced was transported by rail.
Drilling efficiency has also picked up, analysts said, meaning more crude comes out of each well.
While the Permian basin in Texas has become known as the most prolific oil region in the U.S., constraints to getting crude out of the region and transporting it to market have damped enthusiasm for producers working there.
The stocks of Permian basin producers Diamondback Energy Inc. and Concho Resourceshave advanced 7% and 6.5%, respectively, this year, while the broader SPDR S&P Oil and Gas Exploration and Production ETF, or XOP, is up 18% year to date.
“As folks were getting more concerned about pipeline capacity [in the Permian], the capital started to move away,” said Dane Gregoris, senior vice president at RS Energy Group.
Through much of the year, regional oil prices in North Dakota have stayed stronger than in Midland, Texas, where transportation challenges at times pushed prices more than $15 below the U.S. benchmark. But recently that divergence between Midland prices and West Texas Intermediate futures has narrowed, and as of Friday, was $7.10.
And Bakken production is far from overtaking that of the Permian. Bakken oil production averaged 1.3 million barrels a day in September 2018, compared with 3.4 million barrels a day in the Permian, according to the U.S. Energy Information Administration.
Some investors started to turn their attention to other shale plays about a year ago, when constraints in Texas began to emerge, said Mr. Gregoris. “You can see how that’s played out with all these Bakken names.”
“It’s a totally different ballgame,” he added.
https://www.oilandgas360.com/the-hottest-oil-trade-is-no-longer-in-texas/
Crude oil imports by China's independent refineries rose 2.8% on the month and 8.5% on the year to 7.26 million mt or 1.77 million b/d in September, driven by higher feedstock demand following the completion of turnarounds and the rush to use up crude quotas by the end of the year, a monthly survey by S&P Global Platts showed Thursday.
The crude import volume was mostly in line with market expectations, as a slight rebound was expected with the refineries restarting from maintenance shutdowns in September.
"Cargoes that arrived in September were mostly booked around July, when refineries [were optimistic] about future demand, and expected arrivals for October to increase," a source with a Shandong independent refiner said.
The sector's crude imports over January-September inched up 1.3% year on year to around 71.9 million mt, the Platts survey showed.
Platts' survey covers the barrels imported for independent refineries via the ports mostly in Shandong province and Tianjin, as well as those for the upcoming greenfield independent mega Hengli Petrochemical refinery in Liaoning province and Zhejiang Petrochemical refinery in Zhejiang province. The barrels include those imported directly by refiners and trading companies, which will be consumed by the independent sector.
Dongming Petrochemical, ChemChina, Hongrun Petrochemical and Chambroad Petrochemical were the top four buyers in September, receiving a combined 3.21 million mt of crude or 44.2% of the total.
Dongming was the biggest importer with around 1.198 million mt of crude arriving last month, spiking 130% on the month. The refinery received its first Kuwaiti crude cargo of 260,000 mt in early September, replacing the Merey crude it usually buys to produce asphalt.
AROUND 50 MILLION MT OF QUOTAS LEFT
The rebound in September crude imports can also be attributed to the rush in using up crude quotas before the end of the year, according to market sources.
Independent refineries usually need to use up their quota allocation before the end of the year, in an effort to secure a 100% allocation of its ceiling quota for the year ahead.
Taking September arrivals into account, the quota holders were likely to have used up 59% of their total quota for the year, with around 50 million mt still available for October-December imports.
The remaining quotas are, however, not equally shared by the refineries, meaning that a few refineries will probably be short of quotas, while some other refineries may not use up the quotas, though they have the option to sell them.
Some of the refineries that have more than enough quotas for October-December include Baota Petrochemical, Yanchang Petroleum, Qingyuan Petrochemical, Haiyou Petrochemical, according to a trader source.
Platts' survey covered 38 crude import quota holders, which have been awarded a total quota of 121.91 million mt this year. This accounts for 86.9% of the county's total crude import quota allocation for independent refineries in 2018.
Chengda New Energy -- formerly known as Yongxin Petrochemical -- and Kelida Petrochemical end-September received crude quotas totaling 1.08 million mt, enabling them to bring in the cargoes on time, according to documents released by the Ministry of Commerce.
ZHEJIANG AND HENGLI CONTINUE TO HAVE CARGOES
Zhejiang Petrochemical and Hengli Petrochemical, which are likely to delay the startup of their greenfield refineries with a capacity of 20 million mt/year each, have continued to receive crude cargoes in September, according to company sources.
These two refineries will each continue receiving one VLCC cargo every month over October-December. Both of them have planned to start up later this year, the company sources said.
Hengli Petrochemical received a 260,000 mt cargo from Saudi Arabia, half made up of Arab Heavy and the other half Arab Medium. Its next cargo from Saudi Arabia is likely to arrive late October.
Zhejiang Petrochemical has signed a long-term crude contract for 2018 with Saudi Aramco, with volumes unknown.
U.S. crude oil refinery inputs averaged 16.2 million barrels per day during the week ending October 5, 2018, which was 352,000 barrels per day less than the previous week’s average. Refineries operated at 88.8% of their operable capacity last week. Gasoline production decreased last week, averaging 9.7 million barrels per day. Distillate fuel production decreased last week, averaging 5.0 million barrels per day.
U.S. crude oil imports averaged 7.4 million barrels per day last week, down by 568,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 7.8 million barrels per day, 5.3% more than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 693,000 barrels per day, and distillate fuel imports averaged 187,000 barrels per day.
U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 6.0 million barrels from the previous week. At 410.0 million barrels, U.S. crude oil inventories are at the five year average for this time of year. Total motor gasoline inventories increased by 1.0 million barrels last week and are about 7% above the five year average for this time of year. Finished gasoline inventories decreased while blending components inventories increased last week. Distillate fuel inventories decreased by 2.7 million barrels last week and are about 4% below the five year average for this time of year. Propane/propylene inventories increased by 1.5 million barrels last week and are about 7% below the five year average for this time of year. Total commercial petroleum inventories increased last week by 11.3 million barrels last week.
Total products supplied over the last four-week period averaged 20.3 million barrels per day, up by 0.2% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.2 million barrels per day, down by 2.6% from the same period last year. Distillate fuel product supplied averaged 4.2 million barrels per day over the past four weeks, up by 8.2% from the same period last year. Jet fuel product supplied was up 1.7% compared with the same four-week period last year.
Last Week Week Before Last Year
Domestic Production '000..... 11,200 11,100 9,480
Alaska .. .................................... 486 482 503
Lower 48 .............................. 10,700 10,600 8,977
Imports ................................... 7,397 7,965 7,617
Exports ................................... 2,576 1,723 1,270
Cushing up 2.4 mln bbls
Sanctions on Iranian oil exports are hitting much harder than most people predicted as the administration of U.S. President Donald Trump takes a tough line on enforcement, said executives from the world’s largest energy traders.
Perhaps 2 MMbpd of Iranian crude could eventually be lost to the global market, said Jeremy Weir, chief executive officer of Trafigura Group Pte. While other traders including Vitol Group of Cos. and Gunvor Group saw the impact closer to 1 million, that’s still twice as much as most people initially predicted.
"Iranian exports of crude oil will be much reduced,” Vitol Chairman Ian Taylor said in a Bloomberg television interview. That’s largely the cause of the severe “fear factor” in the crude market that’s driven prices up to $85/bbl, he said.
The traders speaking at the Oil and Money conference in London, which included Gunvor CEO Torbjorn Tornqvist and Glencore Plc’s head of oil and gas Alex Beard, weren’t universal in their predictions for prices. Crude futures at $100 or higher were possible by year-end, said Tornqvist, while Taylor saw the market drifting $5 or $10 lower by January.
“We don’t have a supply squeeze, there’s plenty of oil around” right now despite the sanctions, said Taylor. With current prices, demand could start to weaken, he said.
Efforts by the European Union to preserve the international nuclear deal with Iran by setting up a payment mechanism to circumvent U.S. sanctions won’t help oil buyers, the trading-house executives said.
"I don’t see any chance that the European payments mechanism on Iran could work," said Beard. When asked if there was anything that would tempt oil traders to skirt U.S. sanctions, such as the oil market tightening significantly or Tehran offering discounts, Taylor was emphatic: "No, no, and no."
Beard expected the sanctions to stay in place for a long period as the ultimate U.S. aim was "regime change," which would take time if done by squeezing Iran’s oil revenues.
https://www.worldoil.com/news/2018/10/10/top-oil-traders-say-iran-sanctions-hit-harder-than-expected
OPEC cut its forecast of global demand growth for oil next year for a third straight month on Thursday, citing headwinds facing the broader economy, and key consuming countries in particular, from trade disputes and volatile emerging markets.
In its monthly report, the Organization of the Petroleum Exporting Countries said world oil demand would increase by 1.36 million barrels per day (bpd) next year, marking a decline of 50,000 bpd from its previous estimate.
The group also cut the estimate for demand in 2019 for its own crude by another 300,000 bpd from last month to 31.8 million bpd, which in turn marks a decline of 900,000 bpd from the projection for 2018.
OPEC said its own production rose by 132,000 bpd in September to 32.76 million bpd, the highest according to the monthly report since August 2017.
Saudi Arabia and Libya increased output last month by 108,000 bpd and 103,000 bpd respectively, more than offsetting the 150,000-bpd decline from Iran to 3.447 million bpd, as reported by secondary sources.
OPEC said Iran told the group its oil output had fallen by just 51,000 bpd to 3.775 million bpd.
The group, led by Saudi Arabia, has pledged to increase output to compensate for the loss of any Iranian supply to U.S. sanctions that come into force next month.
OPEC cut its forecast for growth in non-OPEC oil supply in 2019 by 30,000 bpd to 2.12 million bpd.
Rising shipping rates have increased the costs of shipping oil from the United States to Asia and may further the restrict the flow of U.S. oil to the region later this year, multiple trade and shipping sources said on Thursday.
Freight rates for tankers that carry crude oil have soared globally, buoyed by peak seasonal demand, weather disruptions and higher bunker fuel costs, the sources said.
The cost of chartering a Very Large Crude Carrier (VLCC) capable of carrying 2 million barrels of crude from the U.S. Gulf coast to South Korea and Japan rose to above $7 million this week, $1 million to $2 million higher than the previous week, according to a shipbroker.
Shipping a barrel of oil from the Louisiana Offshore Oil Port in the Gulf of Mexico on a VLCC to the Southeast Asian refining centre of Singapore costs $3.26 as of Oct. 10, up from $1.78 a month ago, according to data on Refinitiv Eikon. TD-LPP-SIN
“The freight is really expensive these days making every crude grade more expensive,” said an oil buyer in North Asia, who is currently comparing economics for crude arriving in January to decide which grades they will buy.
A Singapore-based trader said U.S. crude prices will have to weaken relative to crude from other countries before resuming strong flows to Asia.
U.S crude arrivals to Asia are expected to fall in November to 19 million barrels, the lowest since March, as buyers baulked at higher prices, according to the sources and data on Refinitiv Eikon.
Chinese refiners have also limited their U.S. crude purchases amid concerns that Beijing could impose import duties on U.S. oil as part of its trade war with the United States.
Unipec, the trading arm of Asia’s largest refiner Sinopec , resumed U.S. oil liftings to China in September with shipments loaded onto the VLCC New Courage. The ship is scheduled to arrive in eastern China on Nov. 21, shipping data on Refinitiv Eikon showed.
Other Chinese buyers have refrained from purchasing U.S. oil while sourcing crude from other regions.
“With freights where they are, we are likely to see shorter haul movement into Europe,” said Virendra Chauhan, an analyst at Energy Aspects.
The drop in U.S. oil flows to Asia could further pressure U.S. spot crude prices as producers grapple with limited pipeline capacity to drain excess supplies, the sources said.
It could also drive up U.S. exports to Europe and displace North Sea and Mediterranean crude grades, they added.
Chinese oil buyers are making a beeline for a bargain across the Pacific.
With Canadian oil over 60% cheaper than U.S. benchmark West Texas Intermediate and global marker Brent, China’s refiners are being lured to the heavy, sludgy crude. That’s because -- apart from being a source of fuel -- it’s rich in bitumen, a black residue used to build everything from roads to runways and roofs.
China’s demand for the material is expected to increase as President Xi Jinping’s government focuses on infrastructure construction in a bid to reform the world’s second-biggest economy. With the availability of other bitumen-yielding oil varieties such as Venezuela’s Merey shrinking, the Asian nation’s refiners are turning to alternative supplies to feed the building boom at home.
One of their options is Canadian crude, prices for which are tumbling as rising production runs into pipeline bottlenecks and maintenance work cuts refinery capacity at regular buyers in the U.S. Midwest. In the rest of the world, oil is surging as impending American sanctions squeeze Iranian exports and an economic crisis hits Venezuelan shipments. Fears are rising that OPEC will struggle to ease a looming supply crunch.
“The policy of boosting infrastructure investment has been bullish for bitumen,” said Li Haining, an analyst with industry consultant SCI99 in China’s Shandong province. “The supply of the Merey grade has been disrupted since May, pushing refiners to look elsewhere. As late-September and October is traditionally the peak season for construction projects in China, demand will be further supported.”
China bought 1.58 MMbbl of Canadian crude for loading in September, almost 50% higher than the 1.05 MMbbl in April, data from cargo-tracking and intelligence company Kpler show. State-run refiner Cnooc Ltd. has chartered a tanker, Nordtulip, to load oil from Vancouver in October, according to shipping fixtures.
With Chinese infrastructure spending in the second half of 2018 seen accelerating at five times the pace in the first six months of the year, expectations that bitumen demand will increase have boosted prices of the material to a record in the nation. That means refiners producing the residue from relatively cheap Canadian oil would enjoy better profit margins.
The heavy Western Canadian Select crude grade’s discount to U.S. WTI was said to have expanded to $50 on Wednesday. The absolute price of WCS was near $26/bbl. On Thursday, Brent crude -- the benchmark for more than half the world’s oil -- was trading at $81.48/bbl in London.
Heavy Demand
Apart from Canada, China has also turned to producers such as Brazil for alternatives, said WengInn Chin, a senior oil market analyst at industry consultant FGE in Singapore. Demand for heavy crude is particularly high among the Asian nation’s independent refiners, known as teapots. The Kpler data shows that the Canadian shipments to China are being delivered to northeast ports including Qingdao and Yantai, which serve these processors.
As the teapots face competition from new mega refineries and increased regulatory scrutiny, they are exploring strategies to stay profitable. Given that the companies have historically been adept at processing heavy crude or residual fuel oil, they could be well-positioned to capitalize on the demand for bitumen and cheaper Canadian oil, according a Bloomberg survey of three traders who participate in the market.
“On the demand side, there are expectations for bitumen growth in China due to a boost in infrastructure spending,” said Sophie Shi, a Beijing-based analyst with industry consultant IHS Markit. “With traditional heavy oil shipments shrinking globally, trade flows are being reshaped and alternative heavy oil supplies from countries such as Canada are becoming sought after."
https://www.worldoil.com/news/2018/10/11/china-swoops-in-on-canadian-oil-thats-50bbl-below-us-crude
OPEC, which has resisted the US' calls to fully unleash its spare crude oil production capacity, presented another bearish outlook for the oil market Thursday, lowering its forecast of 2019 demand for the fourth straight month.
OPEC has raised its crude production in recent months to help offset looming US sanctions on Iran but says it needs to proceed cautiously despite rising oil prices, for fear of flooding the market next year.
The forecasts in the bloc's latest closely watched monthly oil market report explain the circumspection.
Global consumption next year will reach 100.15 million b/d, OPEC said in the report, 80,000 b/d less than it had projected in September, as the producer group sees less economic growth in Europe and Latin America.
Supplies from outside the bloc, meanwhile, will rise to 61.89 million b/d in 2019, the report found, "with potential skewed to the upside." That is 180,000 b/d more than September's forecast.
In a briefing with reporters Thursday, OPEC Secretary General Mohammed Barkindo said the oil market was "well supplied" but reiterated that the bloc stood ready to pump as much as customers require. Oil prices, despite a sell-off over the past few days, have stood near four-year highs this month, with many analysts saying a supply squeeze could be coming from the US sanctions on Iran, which go into force November 5, and Venezuela's continued collapse.
"The market has been reacting to perceptions of a supply shortage, [but] it is not really as such," Barkindo said on the sidelines of the Oil & Money conference in London. "The balance may be fragile as a result of non-fundamental factors, but I remain confident that we will overcome."
In its report, OPEC projected that demand for its crude will average 33.06 million b/d in the fourth quarter of this year, which is higher than the group's September output of 32.76 million b/d, as estimated by the secondary sources it uses to track production.
But the call on OPEC crude falls considerably to 31.53 million b/d in the first quarter of 2019 and 31.74 million b/d in the second quarter. For the full year 2019, the call will average 31.79 million b/d.
Global oil inventories also grew for the third straight month in August, OPEC said in the report.
Saudi energy minister Khalid al-Falih said at an OPEC/non-OPEC monitoring committee meeting in Algiers last month that the soft market outlook warranted prudence on output policy.
"We could have an oversupply situation," Falih said. "Given where we are today on inventory levels, we need to make sure we don't get into a sustained build of inventories in 2019."
TRUMP SAYS PUMP
Under pressure from US President Donald Trump, who has accused OPEC of colluding to keep prices high, the producer group and 10 allies, including Russia, agreed in June to raise their crude output by a collective 1 million b/d from May levels.
OPEC has accomplished a 580,000 b/d gain through September, not including the Republic of Congo, which joined the organization in June, the report indicated.
Most of that has come from Saudi Arabia, whose September output of 10.51 million b/d, according to secondary sources, is 520,000 b/d higher than it was in May. The kingdom self-reported a production level of 10.50 million b/d.
It has said it can pump as much as 12 million b/d at will, though its full production capacity has never been tested.
Sanctions-hit Iran has seen its output drop 380,000 b/d since May, according to secondary sources, who estimated Iranian production of 3.45 million b/d in September.
The country, however, insists its production has not been affected by the coming sanctions, self-reporting 3.76 million b/d for September, down just 50,000 b/d from May.
Venezuela has lost 190,000 b/d since May, according to secondary sources, who pegged the country's September output at 1.20 million b/d.
Like Iran, Venezuela has self-reported a much smaller drop, saying its September production averaged 1.43 million b/d, a 100,000 b/d drop from May.
BP Plc boss Bob Dudley, among the first to say oil will stay lower for longer, is becoming more confident.
In a sign of the improving times, the British oil major is now planning its investments at $60-$65/bbl oil, raising it from $50-$55 last year, Dudley said Wednesday at the Oil & Money conference in London. While he doesn’t expect sustained prices of $85, it’s unlikely to plummet again.
Some of the world’s most influential traders see a broad range for oil prices in the coming months. Glencore Plc’s Alex Beard said Wednesday crude could rise to as much as $90/bbl in a year’s time while Vitol Group Chairman Ian Taylor predicts $65. Because of this uncertainty, Dudley, Royal Dutch Shell Plc’s Ben van Beurden and Total SA’s Patrick Pouyanne reiterated this week they won’t loosen their discipline on spending, even as they churn out huge amounts of cash.
“Are we now off to the races again with spending? My sense of the industry is it learned such a painful lesson,” Dudley said. “Capital discipline is really important.”
Still, higher prices may remove some spending “tightness,” even as BP will stay within its $15-billion to $17-billion annual investment budget, Dudley said. The company plans to approve a number of new projects that it has worked on with an assumption oil wouldn’t fall below $55/bbl. At least two of these will probably be in India, he told reporters.
Each of the company’s projects will make money at less than $40 oil by 2021, Dudley said.
Balanced, but volatile
Supply and demand in the oil market is balanced, he said, though prices remain choppy. Much of that is “emotional” as traders gauge the impact of U.S. sanctions on Iran’s exports that kick in early next month.
“It’s a very volatile crude world right now,” Dudley told reporters. “It could spike up and it could go down now. There are decisions that could be made that drive it either way.”
Brent crude has gained about 20% since mid-August, helping oil companies boost their cash coffers. BP’s priority remains to use the extra money to reduce debt, Dudley said.
The company expects to complete a $10.5-billion acquisition of BHP Billiton Ltd.’s U.S. shale assets this month, Dudley said. It’s progressing on a $5-billion to $6-billion divestment program to help pay for the purchase as it opens data rooms for older North American gas assets, he said.
U.S. Midwest refinery utilization rates fell to 73.3 percent last week, the lowest levels on record, according to the EIA data. The EIA began collecting the Midwest refinery data in 2010.
U.S. East Coast refinery utilization rates fell last to 68.9 percent, the lowest levels for this time of year since 2013, EIA data showed.
Thanks to the consensus view of stable to higher oil prices, U.S. oil and gas mergers and acquisitions (M&A) activity in the third quarter jumped by 250 percent from Q2 to stand at a total of value of US$32 billion, energy data analytics company Drillinginfo said on Thursday.
The value of the Q3 M&A activity in the U.S. oil and gas industry broke all quarterly records dating back to the fourth quarter of 2012. The US$32-billion worth of M&A deals was 76 percent higher than the quarterly average of US$18.3 billion since 2009, Drillinginfo said.
The factors for the record-breaking Q3 M&A activity included more than US$50 billion worth of deals for sale as of July 1, and the view that oil prices will be stable or higher going forward.
The deal highlight during the third quarter was BP buying world-class assets from BHP in the Permian, the Eagle Ford, and the Haynesville basins for US$10.5 billion—the biggest acquisition for BP since buying Arco in 1999.
The other notable deal in Q3 was Diamondback Energy buying Energen in an all-stock transaction valued at around US$9.2 billion, which creates the third-largest pure play Permian company in terms of production.
The Diamondback Energy-Energen deal value is just shy of the Permian record of US$9.5 billion paid by Concho Resources for RSP Permian in the first quarter this year, Drillinginfo says, noting that the Concho and Diamondback deals in the Permian are the start of a trend toward consolidation in the shale patch, rather than “one-off style hits.”
Related: Gazprom's Bid To Maintain European Energy Dominance
Drillinginfo expects the M&A activity to remain high over the next six to 12 months, as there are deals worth US$30 billion for sale. Consolidation will likely continue, while the Permian takeaway capacity constraints could be strategic opportunities for deals over the next 18 months.
“Shale basin consolidation will be a continuing theme supplemented by occasional major new entrants for those few large and global companies who have not yet established a significant shale presence. Private equity and private companies will continue to play a role in deploying carefully calculated risk dollars to fringe areas and benches within established resource plays plus advancing today's technology to new areas like the Powder River Basin as well providing inventory as they move to divest mode,” Drillinginfo Senior Director Brian Lidsky said.
The completion of a large natural gas pipeline from Texas to Mexico has been delayed until April 2019 due to weather conditions and delays in the completion of the Mexican portion of the project.
The 2.6 billion cubic feet a day Valley Crossing Pipeline is being built by Canada's Enbridge, a major petroleum pipeline and storage company, which asked for a six month extension for putting the Valley Crossing Pipeline into operation. It was originally planned to start operations this month, but now has until April 23, 2019, to commence operations.
Enbridge noted that the delay was due to an inability to test the pipeline due to delays in the completion of the Mexican portion of the pipeline, which connects with the Enbridge section offshore from Brownsville in the Gulf of Mexico. The Mexican portion is being built by Infraestructura Marina de Golfo, a joint venture between the Canadian pipeline and storage company TransCanada and Sempra Energy of San Diego. Both companies have major stakes in oil and gas pipeline and storage projects in Mexico.
When completed the pipeline would be the largest natural gas pipeline flowing from the U.S. to Mexico.
Natural gas exports by pipeline from the U.S. to Mexico have more than doubled since 2014, when exports for the year were more than 728 billion cubic feet. In 2017 natural gas exports by pipeline to Mexico were more than 1.5 trillion cubic feet, according to data from the Department of Energy.
Russian natural gas company Gazprom will complete the construction of a 930 km long sea section of the TurkStream in two months, the CEO of Gazprom Alexey Miller said at the International Gas Forum in St. Petersburg on Thursday.
The construction of the TurkStream, natural gas pipeline from Russia to Turkey, started in May 2017. Gazprom plans to begin supplying gas through the TurkStream at the end of 2019.
The TurkStream runs from Russkaya compressor station near Anapa in the Krasnodar region of Russia across the Black Sea to Kiyikoy in northwestern Turkey.
The St. Petersburg International Gas Forum is a platform for interaction between gas industry leaders. Enditem
http://www.china.org.cn/world/Off_the_Wire/2018-10/05/content_64852653.htm
Petrobras completes Mero well test
Launched in November 2017, production was carried out by FPSO Pioneiro de Libra, the first Petrobras extended well testing dedicated unit equipped to inject the gas produced.
According to Petrobras’ statement on Thursday, the EWT was concluded on Tuesday, October 2.
During the tests, the producer well connected to the platform achieved 58 thousand barrels of oil equivalent per day (boed) in production, which is a great result in ultra-deep waters, Petrobras noted. The technological achievements attained during this period were fundamental to obtaining high-quality data and reduce uncertainties about the reservoir, which will enable the accelerated deployment of up to four final production systems in Libra in the coming years. Each system will be capable of producing up to 180 thousand barrels of oil per day.
With the completion of the tests, the FPSO Pioneiro de Libra will operate the subsequent Early Production Systems (EPS) in other Mero wells. The next step consists in the replacement of the current gas injector well by another one located closer to the producer well. After this step, the vessel will be unanchored and displaced to a new location in the Mero field, to move forward with the EPS program. Pioneiro de Libra is capable of processing up to 50 thousand barrels of oil and 4 million cubic meters of associated gas on a daily basis.
New technologies
Located in the Southeastern region of Brazil, Libra is one of the most robust oil and gas production projects ever developed by the offshore industry worldwide, Petrobras stated. The area features reservoirs that are among the most productive in the country, with oil columns that reach up to 400 meters in thickness – the equivalent to the height of the Sugar Loaf mountain.
The high flow rates and pressures, the significant presence of gas associated to oil, in addition to the high content of CO2 in the area have demanded the development of latest-generation solutions to facilitate production. As such, Petrobras and its partners have developed new technologies designed to operate in these environments, with water depths ranging from 1700 to 2400 meters, and total depths that reach up to 6 thousand meters.
One of the solutions was to install in the area the first FPSO dedicated exclusively to Extended Well Tests capable of re-injecting the gas produced. This innovation brings better results to the consortium and the environment, because it allows the elimination of continuous burning of gas, thus minimizing CO2 emissions into the atmosphere and enabling the production of wells at their maximum potential. To produce during EWT without restrictions allowed to optimize the acquisition of dynamic data from the reservoir.
In the deployment of the EWT, the first pre-launch of flexible lines with floats in ultra-deep waters was carried out. This method anticipated the start of well production by 43 days, compared to a scenario without the pre-release of the lines.
The use of flexible ducts for the production measuring 8 inches in diameter, in ultra-deep waters and in a setting known as lazy wave, allowed to obtain large production at such a depth. Due to the loads imposed to the 8-inch lines, the FPSO Pioneiro de Libra has an external turret anchoring scheme with the greatest support of the vertical load in the world’s industry, with a capacity of 700 tons per underwater line (riser), the equivalent to the weight of 4 Boeing 747 aircrafts. This equipment is responsible for supporting the load of nine lines at water depths of up to 2,400 meters.
The Libra consortium also used a robust swivel, which is an equipment that allows the ship to rotate in relation to the turret, which is fixed to the bottom of the sea through mooring lines. This installed model supports the largest operating (550 bar) and design (605 bar) pressure of gas injection in the global oil industry.
The consortium is led by Petrobras – with a 40% stake – in partnership with Shell (20%); Total (20%); and the Chinese companies CNPC (10%) and CNOOC Limited (10%). The consortium also has the participation of the state-owned enterprise Pré-Sal Petróleo – PPSA, which operates as contract manager.
https://www.offshoreenergytoday.com/petrobras-completes-mero-well-test/
US LNG exporter Cheniere has filed a request to the Federal Energy Regulatory Commission to introduce refrigerants to the Sabine Pass LNG train 5.
In its filing to FERC Cheniere requested the permit be granted no later than October 11, in order to continue its commissioning activities on schedule.
Cheniere has already been granted authorization to introduce feed gas for commissioning activities.
Cheniere is developing up to six trains at the Sabine Pass site, each capable of producing 4.5 mtpa of the chilled fuel each.
Mid-September Cheniere Energy has entered into a long-term liquefied natural gas (LNG) supply dealwith Swiss-based energy trading company Vitol for 0.7 mtpa of LNG over a 15-year period.
https://www.lngworldnews.com/cheniere-asks-to-feed-refrigerants-to-sabine-pass-lng-train-5/
Singapore authorities have proposed applying new control standards in the marine fuels sector supply chain, a spokeswoman for the government agency Enterprise Singapore said on Thursday.
The Technical Committee for Bunkering has submitted a proposal to the national standards body, Enterprise Singapore, for a new standard on quantity, measurement and sampling requirements for transfer of bunker fuel from oil terminals to bunker tankers using mass flow metering, the spokeswoman said.
“This proposed standard complements existing standards to ensure transparent and fair trade in the bunkering ecosystem,” the spokeswoman said.
Singapore is by far the world’s largest marine refueling, or bunkering, hub where authorities have implemented some of the industry’s strictest rules and standards.
The city-state was the first port to mandate the use of mass flow meters (MFMs) in 2017, and in the same year posted record sales of marine fuels at 50.6 million tonnes.
Despite existing measures, the marine fuels sector is notoriously opaque with its fair share of scandals including illegal short-selling of fuel as well as large-scale fuel theft.
More recently, a wave of contaminated fuel that has clogged and damaged engines on hundreds of oil tankers and container vessels in the past months, with no one yet held accountable, has pushed shippers to demand stricter controls around the world.
While the proposed measures are not foolproof, they could enhance transparency and accountability in a meaningful way, two trade sources said.
For instance, mass flow meters at oil terminals would ensure the right quantities of fuels are transferred between buyers and sellers while taking oil samples at terminals could help prevent the spreading of contaminated fuels once they are detected and enhance accountability if quality disputes arise, the sources said.
The sources declined to be identified as they are not authorized to speak to the media.
“The proposal will undergo a one-month public notification to seek views of stakeholders on the scope of the standard at the end of this year,” the Enterprise Singapore spokeswoman said.
ExxonMobil is interested in potential Mexican refining projects under the term of President-elect Andres Manuel Lopez Obrador, a senior company official said Thursday.
The US energy giant is looking forward to discussing mutual interest opportunities with the incoming administration, Carlos Rivas, ExxonMobil Mexico's fuel director, told S&P Global Platts in an interview.
"We are allies of Mexico and we want to contribute in the country's energy security," Rivas said. ExxonMobil officials have not able to meet with Lopez Obrador's transition team, he added.
Rivas said ExxonMobil is opened to all refining project opportunities, including taking a stake at a new state-led refinery the incoming administration wants built in the port of Dos Bocas, Tabasco state. The company is also open to partnering with state Pemex at one of its existing refining facilities or adding new processing equipment, he added.
"We are looking all opportunities that can benefit the country," Rivas said.
LEADING PRIVATE GASOLINE IMPORTER
ExxonMobil has started importing and selling refined products in the greater Monterrey area, in the northeastern state of Nuevo Leon. On September 26, ExxonMobil and Mexican partner Orsan opened 34 Mobil-branded stations in Nuevo Leon. The company also began operating at Bulkmatic's Salinas Victoria unit train terminal in the greater Monterrey area. As a result of this move, ExxonMobil expects to end the year with 200 Mobil-branded stations across seven states in Northern and Central Mexico, Rivas said. Over the last 10 months, ExxonMobil has imported 2.5 million barrels of gasoline through 45 unit train deliveries, he added.
As a result of its expansion to Nuevo Leon, Rivas expects ExxonMobil to import as much as 300,000 barrels of gasoline per month by the end of the year. This would place ExxonMobil as one of Mexico's largest private importers of gasoline, alongside Andeavor and Glencore. ExxonMobil sources its gasoline from its Beaumont and Baytown, Texas, and Baton Rouge, Louisiana, refineries, Rivas said.
Private companies imported 835,000 barrels of gasoline into Mexico in August, compared with just 11,000 barrels a year ago, data from Mexico's Energy Secretariat, or SENER, shows. The lack of infrastructure has been a major challenge for private companies to import gasoline. Andeavor has won access to Pemex's infrastructure through open seasons in Northwestern Mexico. Glencore received its first gasoline shipment on August 24 at its new marine terminal at the Port of Dos Bocas in the southern state of Tabasco.
This position has maintained Pemex's dominant position in the market, controlling over 96% of gasoline imports into Mexico in August, SENER data shows.
MEXICO CITY, GUADALAJARA NEXT TARGETS
ExxonMobil wants to become a national fuel wholesaler in Mexico next year, with a key interest in expanding into Mexico City and Guadalajara metropolitan areas. The cities are the largest and second-largest fuel markets, respectively, in Mexico. No private company yet supplies either markets. The major challenge to supplying gasoline to Mexico City and Guadalajara is that each has their own fuel specifications, Rivas said.
ExxonMobil also expects the first phase of Invex's Tajin midstream project to begin operating by mid-2019, boosting ExxonMobil's fuel imports into Mexico's Central region, he said.
For the project's first phase, Invex will complete a new marine terminal at the Port of Tuxpan, Veracruz state, and a storage terminal in Tula, in the northern part of the greater Mexico City region. Fuel would be moved between both locations using trucks, Rivas said. In 2020, a 165,000 b/d pipeline is expected to be completed connecting both places.
Tajin in September became the first private refined products pipeline to receive a permit from Mexico's Energy Regulatory Commission.
"Once Invex's project is up and running, we will improve the energy security in the greater Mexico City region," Rivas said.
Aker BP’s oil and gas production fell 4.6 percent in the third quarter to 150,600 barrels of oil equivalent per day (boed) due to maintenance at two of its fields, it said on Friday.
The company, 30 percent owned by BP, however, maintained its full-year production guidance of 155,000-160,000 boed.
It said production in the third quarter was affected by planned maintenance activities at the Skarv and Alvheim fields, as well as reduced exports from Skarv.
Production from its Valhall field, which it acquired from Hess a year ago, also rose less than it expected due to a longer than planned well testing program.
“As a result, some of the production growth that was expected from Valhall in the third quarter has been moved to coming quarters,” it added.
Valhall output stood at 35,100 boed in the third quarter.
Aker BP shares were 1.2 percent down by 0827 GMT, underperforming European oil and gas index which was down 0.2 percent.
Analysts at Sparebank 1 Markets said the overall third-quarter production was disappointing and may trigger some discussion around downside risk to the company’s overall 2018 guidance.
Shale gas developer Cuadrilla Resources will start fracking for gas at its Preston New Road site in northwest England next week, the company said on Friday.
Hydraulic fracturing, or fracking, involves extracting gas from rocks by breaking them up with water and chemicals at high pressure. It was halted in Britain seven years ago after causing earth tremors.
But the British government, keen to cut its reliance on imports, which have soared to more than 50 percent of British gas supplies, has tightened regulation of the industry.
This year it gave consent for Cuadrilla to start fracking at two wells at Preston New Road.
Results from a six-month test period are expected in the first quarter of next year, which Cuadrilla said would provide information on how much gas it could potentially recover.
“This will allow us to make an assessment of the commercial viability and future of this exploration site,” Cuadrilla chief executive Francis Egan said in a statement.
The British Geological Survey estimates shale gas resources in northern England alone could amount to 1,300 trillion cubic feet (tcf) of gas, 10 percent of which could meet the country’s demand for almost 40 years.
The practice of fracking has been opposed by environmental and local community campaigners concerned about the potential effect on the environment and ground water. They also argue that extracting more fossil fuel is at odds with the country’s commitment to reducing greenhouse gas emissions.
Three protestors were given prison sentences in September for blocking a convoy of trucks carrying drilling equipment to the site.
Sisi says Egypt will become a net gas exporter in April, four years after it imported its first LNG cargo. Will dreams of becoming a regional gas hub materialize?
Egypt has gone from net exporter of gas, to net importer and back again within the span of seven years. This reversal of fortune has been thanks to the sanctioning since 2016 of 25tcf of gas developments, in large part due to swift policy change at the oil ministry. The consensus amongst oil firm executives is that this has mostly been the work of one man, the oil minister, Tariq al-Mulla.
“With the last liquefied natural gas shipments to Egypt last week, we announce a halt on gas imports,” Mr Mulla said on 29 September, echoing President Sisi’s remarks at the UN General Assembly in New York just four days earlier, that Egypt would see a gas surplus in April next year.
Norwegian oil and gas giant Equinor has reduced the estimated investments for operated projects in the development phase on the Norwegian continental shelf by some NOK 30 billion ($3.6 billion) since the development plans were submitted to Norwegian authorities.
This appears from the status for Norwegian projects under development published in the Government’s national budget proposal for 2019, Equinor said on Monday.
Equinor-operated projects that are included in the reporting to the budget are: Aasta Hansteen, Bauge, Johan Castberg, Johan Sverdrup phase 1, Martin Linge, Njord Future, Oseberg Vestflanken 2, Snorre Expansion, Trestakk and Utgard
Margareth Øvrum, Equinor’s executive vice president for Technology, Projects and Drilling, said: “We have successfully reduced the investment estimates by approximately NOK 30 billion since submitting the PDOs to the authorities. The improvements have been achieved in close collaboration with our partners and suppliers, and are mainly a result of increased drilling efficiency, simplification and high-quality project implementation. These figures also include the market effect we have achieved by counter-cyclical investments.”
Adjusting for the currency effects of a weak NOK, the reduction of investments for the portfolio is substantially bigger.
Taking over the operatorship for the Martin Linge project in March 2018 Equinor has conducted a thorough review of the project, establishing a plan for safe start-up. Based on estimates of the remaining work at Martin Linge start-up is scheduled for the first quarter of 2020. The updated investment estimate totals NOK 47.1 billion.
According to the company, the investment estimate for Martin Linge has increased by NOK 3.6 billion since last reporting based on Equinor’s assessment of the remaining scope of work. In addition, the change of operatorship has necessitated an accounting change for the project of NOK 1.35 billion.. This applies to charter rates for storage vessels and historical drilling rig rates.
“When we acquired the stakes in the Martin Linge field and took over the operatorship, we allowed for any remaining work and increased costs. As announced, we have therefore spent time at the Rosenberg yard to get an overview of this. After successful platform installation the focus is now to ensure high-quality completion of the project, and safe start-up of the field,” said Øvrum.
Kuwait Petroleum Corporation, or KPC, is expected to be ready to supply bunker fuel oil with a maximum sulfur content of 0.5% in the fourth quarter of 2019, sources close to the matter said this week.
Kuwait is currently carrying out the Clean Fuels Project, which includes construction of a desulfurization unit and a fluid catalytic cracker.
Kuwait National Petroleum Company, or KNPC, earlier awarded Japanese engineering company JGC Corporation and South Korea's GS Engineering & Construction and SK Engineering & Construction contracts to provide engineering, procurement, construction, pre-commissioning and assistance during commissioning, startup and performance testing services for the Clean Fuels Project at Ahmadi in Kuwait, JGC said in a statement in March 2014.
The project is scheduled to be completed around mid-2019, and after commissioning of the facilities, KPC, a trading company of Kuwaiti oil products, will be able to supply bunker fuel with maximum 0.5% sulfur, a source close to the matter said.
KPC currently sells 2-3 cargoes/month of high sulfur fuel oil with 380 CST viscosity and maximum 4.2% sulfur on a spot basis.
Kuwait will export fuel oil cargoes with maximum 1.0% sulfur from Q1 2020, another source close to the matter said.
The Clean Fuels Project is "a strategic project to expand and upgrade Mina Abdullah and Mina Al-Ahmadi refineries to be an integrated refining complex with a total capacity of 800,000 b/d," KNPC said on its website.
The project includes construction of 16 new units at Mina Al-Ahmadi refinery and 14 new units in Mina Abdullah refinery, KNPC said.
The Trump Administration trade policy is nowhere so clear as in the energy area. For years it was thought that the younger Bush Administration was one of the most energy industry friendly in history. But the Trump Administration has gone far beyond that.
Hiring Ray Tillerson, the former CEO of ExxonMobil, as U.S. Secretary of State, sent a strong signal to the entire industry, even though his tenure proved to be temporary.
Prior to that, the Administration withdrew from the Paris Climate Agreement, a long-held priority of Exxon and the entire oil industry. Following hard upon that, the Environmental Protection Agency (EPA) has reduced or eliminated regulations limiting carbon and other pollutants.
Exxon has for more than a decade underwritten the now discredited, right wing attack on climate change as a hoax. Although the energy industry has now publicly acknowledged climate change as a global threat, in practice the subject is still largely ignored.
Going further, the Trump Administration has removed and reduced regulations that hampered the industry expansion, including allowing drilling on both ocean coast, while easing safety regulations that were brought into effect after BP’s Gulf of Mexico disastrous spill, the worst in U.S. history.
Government protected nature preserves are being opened to exploration and drilling for the first time in generations. Added to that was the dropping of regulations that for many years prohibited export of U.S. crude. Since then, the U.S. has become a major player in the global energy industry.
The Administration currently plans to rescind and lower fuel efficiency standards for autos and trucks. That is likely to encourage increased purchase of larger SUVs, increased oil consumption, and rising gasoline prices.
The Administration corporate tax cut, one of the largest in U.S. history, also strongly benefitted the energy industry, as it did other industries.
From the moment he chose to run for President, Trump has embraced the new shale revolution in the U.S. as a major contributor to the country’s economic growth and energy independence.
Increasingly, Trump has become the top promoter for increasing exports of U.S. Liquid Natural Gas (LNG) to world markets. He openly threatened to place economic sanctions on Germany if it went ahead with the deal for Russia’s new Nordstream 2 pipeline, that would nearly double natural gas supplies from Russia, Germany’s largest supplier.
As most observers noted, the U.S. sanction threat was accompanied by the offer of U.S. LNG to Germany and Europe, as a replacement of Russian gas.
No doubt that Trump’s bullying offended European sensibility, but despite the German protest regarding outside interference in its domestic economic affairs, and its intention to complete the Russian pipeline, Germany is quietly building up LNG importing facilities, "as a gesture to American friends."
Most energy experts agree that it is inevitable that U.S. LNG will eventually become a component of European markets, despite its significantly higher price to Russian and Norwegian gas, if for no other reasons to keep the peace with America, Europe's largest ally, and assure Europe’s access to the U.S. market.
This will also serve to assuage the U.S. complaints about unfair trade. It matters little that the U.S. trade deficit with Germany centers on its auto industry rather than energy, if the sale of natural gas serves to reduce the U.S. trade deficit.
The same could be said about the U.S./China trade deficit. China, the largest energy consumer, is the one country where solutions to the trade deficit is clearly at hand, involving increased U.S. LNG imports. China already has a long-term, 20-year deal to import LNG from the leading U.S. LNG company, Cheniere Energy.
China could easily reduce the amount of gas imports from variety of other suppliers (i.e., Qatar, Australia, New Guinea, Iran, Russia) and replace these with U.S. supplies. That would be a near costless transaction for China, as it is already paying other producers for natural gas and LNG supplies.
Consider the effects of a possible LNG deal could have on the trade dispute. In terms of the current deficit, China sales to the U.S. is estimated at around $350 billion, while U.S. sales to the China is around $150 billion.
Last May, the China signed a $25 billion deal for importing U.S. LNG. If we assumed that in current negotiations the two countries could strike a modest deal for another $25 billion in annual U.S. LNG sales to China, U.S. sales to China increases to $200 billion, reducing China’s surplus to $300 billion.
If that were to take place, the trade deficit would reduce to around $100 billion, and Trump would no doubt return to the election campaign trail to boast of the first U.S. trade victory over China.
The risk to this scenario is the presumption that everyone involved really wants a solution to the trade dispute, but there is widespread suspicionsthat U.S. tariffs on China may be less about fair trade and more about economic warfare to contain China’s growth.
George Friedman's "Geopolitical Futures" recently noted that "The U.S. is beginning to see it [tariffs] more as a strategic opportunity to contain Chinese assertiveness than as a play to invigorate U.S. manufacturing."
On various Asian websites, there remains a stalwart band of journalists, led by Pepe Escobar, who maintain that Europe, Russia, China, and Iran will band together to thwart U.S. sanctions on Iran, and that 'Iran's oil sales will be totally unaffected. They also hold strongly to the opinion that China will not yield to U.S. threats and ultimatum.
This despite the fact that major energy companies, like Royal Dutch Shell and Total have already fled Iran in fear of US sanctions, while major countries are severely cutting Iran imports.
Sanctions against Iran will certainly reduce its exports substantially, with the worst case estimates of a loss to the markets of 1.5 million barrels of oil per day. This will also open opportunities in under supplied markets that will almost certainly be exploited by U.S. and other competitors.
Currently, Japan and India have agreed to major reductions of energy imports from Iran. Recent news has it that Sinopec, China’s largest oil and gas refiner, under threats of US sanctions, also agreed to severely cut imports from Iran. It's no secret that nearly all of Iran’s competitors, it's OPEC 'partners', will go after those under supplied markets, as will the U.S.
Some observers believe that because the upcoming election is uppermost in the minds of both U.S. political parties, a trade victory with China is extremely important to the Republican election campaign. If so, their thinking goes, a deal will result in easing tariffs with China by November.
Trump himself recently stated that he's ready to talk trade with China, but continues to add the qualifier, "not now." Many Trump watchers interpret this to mean that 'getting tough with China' plays well to Trump's base, boosts the Republican election prospects, and afterwards a trade deal is likely to be struck.
Any trade deal with China could also be used by the U.S. as a template for deals with Japan, India, and South Korea, the next largest Asian importers of natural gas. It can hardly be coincidence that, as in Europe, these energy importing countries are threatened by US tariffs over unfair trade.
However, Geopolitical Futures states that "the broad impression in China appears to be that Trump isn’t actually interested in a deal – certainly not one that China could accept – and that this is just the first major salvo in an emerging Cold War and that instead ... the world needs to get ready for a new cold war with China.
In a recent speech, Richard Haas, president of New York-based think tank Council on Foreign Relations stated that "...the Trump administration initially focused just on trade, “but now it’s broadening, and it almost seems as if the administration wants to have something of a cold war with China.”
What about Venezuela, a country estimated to have the largest oil reserves in the world, also laboring under U.S. sanctions? It's also a country about which the Administration has made no secret of its plans for a possible U.S. military invasion to topple the Maduro government.
Why go public with that story now, with only a little more than a month towards U.S. Congressional elections?
There is widespread speculation that this announcement may be a trial balloon, as part of the preparation for laying the ground work for an invasion aimed at bolstering Republican election prospects. To date, there has been no sign of opposition to these threats from Democrats.
Conclusion:
It's no accident that sanctions are aimed at the U.S. largest energy competitors, Russia and Iran, nor is it coincidence that the largest energy importers, Europe, China, Japan, south Korea are also under threat of U.S. tariffs or sanctions.
Instead, it clearly shows that the U.S. is using the threat of economic warfare and possible military conflict as leverage to open markets to the newest player on the world's energy market, American LNG.
If the U.S. is successful in these deals, it's likely that in future, there will be a parallel attempt to make inroads for US crude export to the very same oil importing countries, relying upon the very same LNG game plan.
China reported on October 8 its total output of shale gas in the field of Fuling, southwest of the country has exceeded 20 bln cu metres.
Offshore driller Ensco Plc said on Monday it plans to buy smaller rival Rowan Cos Plc in an all-stock deal valued at $2.38 billion, as it looks to expand its fleet and benefit from a partnership with Saudi Aramco.
This is Ensco’s second deal since OPEC-led efforts boosted oil prices in the second half of 2016. Ensco bought rival Atwood Oceanics in a similar deal last year.
Rowan shareholders will receive 2.215 Ensco shares for each share held. Following the close of the deal, Ensco shareholders will own 60.5 percent of the combined company.
The combined company, which will have an enterprise value of about $12 billion, will have a fleet consisting of 28 floating rigs and 54 jack-ups with drilling operations in the Gulf of Mexico, Brazil and West Africa, among others.
The company will benefit from Rowan’s strategic joint venture with Saudi Aramco, Ensco CEO Carl Trowell said.
Rowan formed ARO Drilling with the state oil giant in 2016 to operate offshore drilling rigs in Saudi Arabia. The Ensco deal excludes Rowan’s 50 percent interest in ARO Drilling.
Baker Hughes, the world’s second-largest oil services company, will take a 5 percent stake in Abu Dhabi National Oil Company’s (ADNOC) drilling unit for $550 million under a tie-up announced on Monday.
Baker Hughes (BHGE) becomes the first foreign company to take a stake in one of state-owned ADNOC’s services companies under the agreement which values ADNOC Drilling at about $11 billion.
It will allow Baker Hughes to cement its presence in the Middle East, the fastest growing region for oil and gas operations, and enable ADNOC Drilling to gain access to the know-how and technical expertise of a global player.
Since its acquisition by General Electric Co last year, Baker Hughes has sought new business models following a sharp decline in global drilling activity since 2014. That includes offering a suite of services to oil and gas producers from exploration to drilling.
“To us this is not just another partnership... this will allow ADNOC Drilling to be not only a local player but a global specialist in the drilling and oil service business,” ADNOC’s Chief Executive Sultan al-Jaber told Reuters in an interview in Abu Dhabi.
It would help make ADNOC Drilling “the most efficient and the most competitive,” al-Jaber said.
Baker Hughes’ CEO Lorenzo Simonelli said BHGE will have a representative on the board of ADNOC Drilling and will create a dedicated training team.
The partnership will offer drilling services in the UAE and possibly abroad as well, al-Jaber said.
The transaction is expected to close before the end of this year, with operations starting in 2019, ADNOC and BHGE said in a joint statement.
Al-Jaber said “there are no plans at this point of time” to float a stake in ADNOC Drilling.
Moelis is acting as the financial adviser to ADNOC on the transaction, while Citi is the adviser to BHGE, the two companies said in the statement.
Hamburg-headquartered shipping company Hapag-Lloyd is set to trial an LNG-conversion vessel during 2019, as it looks to keep the costs down amidst new IMO regulation.
With a stricter International Maritime Organisation emissions regulation (IMO 2020) coming into force as of January 1, 2020, the new sulphur cap for compliant fuel oil will be lowered from 3.5 percent to 0.5 percent.
This new regulation is aimed a improving the ecological footprint of the shipping industry, and the majority of all vessels are expected to be operated with low-sulphur fuel oil by then.
Using low-sulphur fuel oil will be the key solution for the shipping industry and Hapag-Lloyd to remain compliant, the company said in its statement.
At the same time, the utilization of the compliant low-sulfur fuel oil comes along with an increase in fuel costs, which experts estimate to initially amount up to $60 billion annually for the entire shipping industry.
On the assumption that the spread between high-sulphur fuel oil (HSFO) and low-sulphur fuel oil (LSFO 0.5%) will be $250 per tonne by 2020, Hapag-Lloyd estimates its additional costs being around $1 billion in the first years.
Therefore, the company developed a Marine Fuel Recovery mechanism, which will be gradually implemented from January 1, 2019, and replace all existing fuel-related charges.
In addition to the LNG conversion vessel, Hapag-Lloyd intends to conduct trials using exhaust gas cleaning systems (EGCS) on two others during 2019.
https://www.lngworldnews.com/hapag-lloyd-to-trial-lng-conversion-vessel-in-2019/
Egypt will begin importing natural gas from Israel under a $15-billion deal as early as March if an undersea pipeline connecting the Mediterranean neighbors is found to be in good condition, moving the country closer to its goal of becoming an energy-exporting hub.
Mohammed Shoeib, chief executive officer of East Gas Co., a major Egyptian partner in the pipeline, said supplies would begin at 100 MMscfd in the first quarter of 2019 and gradually rise to a maximum of 700 MMscfd.
“We expect the pipeline is in good condition,” he told Bloomberg in an interview. “We aim to reach the pipeline’s full capacity or maximum flowrate within three years.”
East Gas and the companies developing Israel’s largest natural gas fields agreed last month to buy 39% of the East Mediterranean Gas Co., which owns the pipeline connecting southern Israel to Egypt’s Sinai peninsula, clearing the main legal obstacle to the 10-year export contract signed in February. East Gas separately made a deal to buy a further 9% from MGPC.
The EMG pipeline was originally built to export Egyptian gas to Israel, but has been idle for about six years.
Testing soon
The partners expect to begin testing the pipeline soon before modifying facilities to reverse the flow, Shoeib said in his first public comments since the deal was announced, adding that the procedures were expected to take three to four months. Once the gas has been flowing for 30 days, the deal will close, he said.
Egypt halted supplies to Israel in 2012 due to a domestic gas shortage and repeated attacks by Islamist militants on a connecting overland stretch of pipeline in the Sinai. It was because of those stoppages that Egypt was embroiled in arbitration cases with some of EMG’s owners, which had threatened to delay the export plans.
Those issues have been all but resolved because East Gas and its partners bought out the litigants, but northern Sinai remains unstable. The army embarked on a months-long campaign this year to root out militants who killed more than 300 people at a mosque in November.
“We are not worried about the security issue,” said Shoeib, who headed Egypt’s state gas company EGAS when the country decided to halt its exports. “We’re confident that the army and police have secured the area well.”
Shoeib, whose East Gas Co. also owns and operates a separate pipeline through Jordan, said that link could be used as a backup in case of problems with the EMG infrastructure or to pump additional quantities if needed.
Win-Win
Egypt announced at the end of last month it had once more become self-sufficient in gas due to a six-fold increase in production at its own giant Zohr gas field. Egypt also has idle liquefaction plants that allow it to export any of its own surplus gas or re-export gas piped in from Israel or elsewhere in the region. For Israel, using existing infrastructure to export via Egypt saves it the cost of building its own facilities.
“It’s a win-win situation,” Shoeib said. “It also sends the message to international investors that Egypt is able to settle disputes and create a good investment climate.”
https://www.worldoil.com/news/2018/10/8/egypt-to-receive-first-israeli-gas-as-early-as-march
Australian LNG player Woodside has selected Bechtel as the preferred execution contractor for the proposed expansion of its Pluto liquefied natural gas facility in Western Australia.
Woodside said on Tuesday it will continue to work with Bechtel in preparation for the award of the contract for the front-end engineering and design (FEED) phase.
Activities will include continuing to refine the concept and costs, Woodside said.
The FEED contract award will also include the option for the full execute phase contract, subject to a positive final investment decision.
Woodside CEO Peter Coleman said expanding the Pluto LNG facility is key to realizing the company’s vision for the Burrup Hub.
“Expanding Pluto LNG will provide the necessary infrastructure to commercialize Western Australian gas resources for years to come,” he said.
Woodside is proposing a brownfield expansion of the Pluto LNG facility, including construction of a second LNG train with a targeted capacity of 4–5 Mtpa, to facilitate the development of the 7.3 Tcf Scarborough gas resource.
Woodside is targeting FEED entry in Q1 2019 and a final investment decision in 2020, with Train 2 targeted to be ready for start-up in 2024.
These targets are subject to all necessary joint venture approvals, regulatory approvals and/or appropriate commercial arrangements being finalized.
https://www.lngworldnews.com/woodside-picks-bechtel-for-pluto-lng-expansion/
The United States has granted BP and Serica Energy a new licence to run a North Sea gas field partly owned by Iran in a rare exemption by U.S. President Donald Trump's administration as it prepares to renew sanctions on Tehran next month.
The waiver extension will allow Serica to complete the acquisition of BP's stake in the Rhum, Bruce and Keith fields, as well as buying Total's stakes in Bruce and Keith, Serica said in a statement.
Rhum, which supplies around 5 percent of Britain's gas demand, is half owned by Iranian Oil Company, a subsidiary of the national oil company.
The U.S. Office of Foreign Assets Control extended a licence for U.S. and U.S.-owned or controlled entities to provide goods, services and support the Rhum field.
Renewed U.S. sanctions on Tehran, which will take full effect on Nov. 4, ban U.S. companies and citizens from doing business with Iranian companies as well as transactions in dollars.
The new licence is conditional on the setting up of an escrow account that will hold all profits from the field for as long as the sanctions are in place, Serica said.
A similar mechanism was set in place in the previous round of U.S. sanctions on Iran.
The new licence is valid until October 31, 2019 and may be renewed upon application, Serica said.
https://uk.finance.yahoo.com/news/u-grants-bp-serica-licence-run-iran-owned-070455565--finance.html
International and Dutch unions filed a complaint with a global trade body on Tuesday accusing Chevron Corp. of funneling billions of euros through letter box companies in the Netherlands to avoid taxation.
In a rare step, the federation of Dutch trade unions, the International Transport Workers’ Federation and Public Services International lodged the complaint with the Organisation for Economic Co-operation and Development (OECD) in The Hague.
Chevron did not respond to repeated requests for comment by email and phone.
Reuters was unable to determine why the U.S. oil major had been singled out in the complaint, but the trade unions said tax avoidance deprived workers they represented of basic government services and pressured their wages.
“The workers and communities we represent suffer when government-provided services such as health care, education, infrastructure, water, energy, and public safety decline.” the complaint said. “Unfortunately, multinationals’ practice of avoiding paying taxes in the countries in which their wealth is earned deepens global wealth inequality and empowers multinationals against workers and governments.”
Scores of multinationals use the Netherlands, which has a network of tax treaties with roughly 100 countries, to shift dividends, interest and royalties untaxed through Dutch shell companies to tax havens overseas.
In their 35-page complaint the unions alleged Chevron had used its Dutch subsidiaries to breach OECD disclosure guidelines in respect of their operations with Chevron’s Nigerian, Argentinian, and Venezuelan businesses. In those examples, the complaint states that Chevron specifically failed to meet requirements to pay tax in the country of extraction and to adhere to Dutch financial disclosure requirements.
The unions’ statement said Chevron’s Dutch subsidiaries, through frequent intra-group operations whose main purpose was the avoidance of taxes in multiple jurisdictions, breached the spirit of Dutch corporation tax law.
“The American company is carrying out tax avoidance on a massive scale,” the groups said in a statement to the media, detailing the complaint.
“The Netherlands is already a tax haven which encourages companies to pay less.”
The Dutch government, which says it wants to help stop tax avoidance, has come under pressure from the OECD and the European Commission to take measures to halt tax avoidance.
A spokeswoman at the Dutch Finance Ministry said the government does not generally comment on cases involving individual companies and had no immediate reaction.
A major complaint expressed by the OECD and the European Commission, is the Dutch finance ministry’s practice of granting “advance rulings”, or agreeing in advance with large corporations on how a given structure will be taxed.
In 2015 the European Commission ordered the Dutch to reclaim up to 30 million euros ($34.7 million) in back taxes from Starbucks after ruling that the tax arrangement with the U.S. coffee company amounted to illegal state aid. Starbucks denied wrongdoing and has appealed.
The global liquefied natural gas market could see a shortage sooner that it was initially anticipated, Qatar Petroleum’s president and CEO Saad Sherida Al-Kaabi said.
Speaking at a conference, Al-Kaabi said the shortage will not only come sooner than expected but it will also be bigger than predicted, Platts reports.
The market tightening is seen as a result of fewer FIDs being reached on new LNG projects.
Qatar Petroleum recently revised its expansion plans, lifting the expansion capacity to 110 mtpa with the addition of a fourth train to its expansion project.
With the addition of the fourth train, the new project will produce about 32 million tons of LNG annually, 4,000 tons/day of ethane, 260,000 barrels/day of condensate, and 11,000 tons/day of LPG, in addition to approximately 20 tons per day of pure helium, the company said in an earlier statement.
Al-Kaabi noted the financial investment on the expansion is expected before the end of 2019 with first production expected before the end of 2023.
He added that no outside investment or any binding LNG supply deals are needed for the expansion to go ahead.
In addition to Qatar’s production capacity expansion, the company could reach a final investment decision on a US-based LNG export project in a few months.
Al-Kaabi said the Golden Pass LNG project would give the company a new access to Latin American and European markets with the first volumes expected to hit the market in 2025.
https://www.lngworldnews.com/qp-ceo-lng-shortage-to-hit-sooner-than-expected/
U.S. shale oil producer EOG Resources on Tuesday warned of a non-cash loss of $52.1 million in the third quarter on commodity derivative contracts in a filing with the U.S. Securities and Exchange Commission.
The Houston-based company attributed the hit to a difference between its realized price for crude oil and natural gas sales during the quarter, and the prices due at NYMEX delivery locations.
Benchmark crude prices averaged $69.50 a barrel during the quarter, EOG said in the filing. It hedged 134,000 barrels per day, or about 35 percent of its prior period’s production, at roughly $60 a barrel.
Analysts still anticipate EOG to report a profit of $1.48 per share in the third quarter compared with a profit of 19 cents in the same quarter last year, according to Refinitiv I/B/E/S.
Losses from hedging contracts will be prevalent in the third quarter across the shale oil and gas industry, said Ben Montalbano, co-founder of Denver based analytics firm PetroNerds.
“This is probably one of the less severe numbers you’ll see this quarter. A lot of their peers have hedged a larger portion of production and done so at a lower price,” he said.
For the roughly 40 companies PetroNerds tracks, the aggregate of swaps and collars were under $60 a barrel, he added.
Last quarter, several producers, including Devon Energy Corp, Anadarko Petroleum Corp and Pioneer Natural Resources, reported losses after missing bets on oil prices. Then, many had hedged around $55 a barrel, but were burned when oil climbed to more than $70 a barrel.
The company would like to have refining operations on the Houston Ship Channel, in the western part of the U.S. Gulf, to complement an existing eastern Gulf refinery in Mississippi that makes lubricants and other materials, Pierre Breber, Chevron’s head of downstream and chemicals, said.
“Something on the ship channel side could make a lot of sense for our company,” Breber said in an interview on the sidelines of the Oil & Money conference in London.
Chevron is a major oil producer in the Permian Basin of West Texas and New Mexico, the largest U.S. oilfield. The company’s Permian production jumped 51 percent sequentially in the second quarter to 270,000 barrels of oil equivalent per day. By expanding its refining capacity to Houston, Chevron would be able to process its Permian crude closer to where it is produced.
Most of Chevron’s refineries are in California and use a heavier type of crude than the light, sweet kind pumped from Permian shale wells.
“The ingredients to invest in the U.S. Gulf are very sound,” said Breber, who assumed his current role in 2016 and previously oversaw Chevron’s pipeline operations.
Rival Exxon Mobil Corp said last year it would invest $20 billion on U.S. Gulf refining projects.
The Houston Ship Channel links the busiest U.S. petrochemical port to the Gulf of Mexico and is home to dozens of refineries and chemical facilities.
Mike Wirth, who became Chevron’s chief executive earlier this year, formerly ran the company’s refining arm and is widely seen by Wall Street as an advocate for expanding refining operations.
Separately, Berber said Chevron’s existing Mississippi refinery has seen shipments from Venezuela drop 25 percent to 75,000 barrels per day over the last two years. Chevron is the only remaining major U.S. oil producer in the strife-torn country.
Companies exploring for oil and gas in Mozambique will spend at least $900 million, boosting the nation’s hopes of becoming a major exporter, Mineral Resources Minister Max Tonela said.
Empresa Nacional de Hidrocarbonetos, the state-owned oil company, will have stakes of 15% to 30% in the projects, Tonela said Monday at a ceremony where the hydrocarbons regulator signed an exploration agreement for oil and gas with Exxon Mobil. The government had previously put the total exploration spend at $711 million.
The offshore concessions are part of the southeast African nation’s fifth licensing round, which Exxon and its partner Rosneft Oil won in 2015. The companies will spend “hundreds of millions” of dollars in exploration, Jos Evens, Exxon’s country head, told reporters in the capital, Maputo, after signing the contracts. The company is analyzing seismic data and will start a “drilling campaign in the coming few years,” he said.
Mozambique is thought to have enough gas to become the world’s fourth-largest exporter of the fuel. The country hopes companies will start producing from 2022, providing much-needed revenue for a government that has been in default on its commercial external debt since announcing it wanted to restructure in 2016.
The national oil and gas regulator said in 2015 Exxon and its partners would spend $527 million drilling five wells in the three blocks.
The country will probably sign agreements with Sasol and Eni of Italy later this month, Tonela said.
Exxon is already developing a floating liquefied natural-gas project together with Eni and plans to reach a final investment decision on the much larger Rovuma LNG project by the middle of next year, Evens said.
Anadarko Petroleum, based in Woodlands, Texas, also plans to make a final decision on its Mozambique gas project next year, which will be similar in size to Exxon’s.
https://www.worldoil.com/news/2018/10/9/oil-explorers-to-spend-900-million-in-mozambique
The price of spot liquefied natural gas contracted during the month of September in Japan jumped 53.6 percent year on year.
Data from the Japanese Ministry of Economy, Trade and Industry shows the contract-based price reached $10.6 per mmBtu, compared to the $6.9 per mmBtu in September 2017.
Compared to the previous month, however, the price was pegged back from $10.7 per mmBtu.
The arrival-based price rose in September to $10.1 per mmBtu from $9.8 per mmBtu during August. Compared to last year, this is a 74.1 percent jump.
Only spot LNG cargoes are taken into account in this assessments, excluding short, medium and long-term contract cargoes, as well as those linked to a particular price index.
https://www.lngworldnews.com/japans-september-spot-lng-price-jumps-yoy/
Japanese refiners have shut a combined 692,700 b/d or 20% of their refining capacity due to a combination of scheduled and unexpected shutdowns, prompting Idemitsu Kosan to import gasoline and trim refined products exports amid uncertainty over the restart of the Hokkaido refinery.
Japan's operable refining capacity has fallen to about 2.83 million b/d -- below the level of domestic demand at around 3 million b/d -- after JXTG Nippon Oil & Energy and Showa Shell shut a combined 190,200 b/d capacity for scheduled maintenance programs last week.
The country's largest refiner, JXTG Nippon Oil & Energy, has shut a combined 367,700 b/d or 19% of its refining capacity of 1.93 million b/d, following the shutdown of the 90,200 b/d No. 2 crude distillation unit at its 180,200 b/d at Mizushima-B plant in western Japan on October 5.
On October 3, Showa Shell shut the No. 2 100,000 b/d CDU at its Yokkaichi refinery in central Japan for about a month-long scheduled turnaround.
The scheduled shutdowns of JXTG and Showa Shell CDUs increased Japan's refining capacity outage to 692,700 b/d, or 20% of the country's installed refining capacity of 3.519 million b/d over 22 refineries, according to S&P Global Platts calculations.
Meanwhile, Idemitsu Kosan has not said when it will be able to restart its 150,000 b/d Hokkaido refinery -- the only refinery on the northern Japanese island -- following an automatic shutdown as a result of the 6.7 magnitude earthquake that rocked Hokkaido on September 6.
Hokkaido is Japan's largest demand center for kerosene, with heating demand likely to pick up and peak in the coming months for the winter.
For fiscal year 2017-18 (April-March), Hokkaido accounted for roughly 17% of the total ex-refinery/oil terminal kerosene shipments of around 291,864 b/d in Japan, according to the Petroleum Association of Japan data.
Idemitsu now transfers gasoline, kerosene and gasoil to the Hokkaido refinery from its 190,000 b/d Chiba refinery in Tokyo Bay and 160,000 b/d Aichi refinery in central Japan as well as getting supplies from its alliance partner Showa Shell to ensure its supplies, a company spokesman said Tuesday.
The Idemitsu spokesman also said the refiner is trimming its exports of products to ensure domestic supplies amid uncertainty over the Hokkaido refinery restart.
While Idemitsu has not detected any trouble or damage at the Hokkaido refinery, it is still running safety inspections in order to restart the refinery at an early date, the spokesman added, declining to elaborate.
Idemitsu chartered a Medium Range tanker, the Yayoi Express, for a South Korea to Japan voyage, loading 35,000 mt of gasoline over October 11, according to a source close to the matter.
Idemitsu is also importing some unspecified products from its leased storage in South Korea to its Hokkaido refinery, the spokesman said, without elaborating.
Traditionally Japan rarely imports gasoline as demand is typically met by domestic production but the country has hiked imports of the light distillate continuously this year against 2017 levels.
Japan's gasoline imports doubled to 54,831 b/d in August from 27,402 b/d in the same month of 2017, and the country's gasoline imports over January-August averaged 34,643 b/d, up 141% from a year ago, according to the Ministry of Economy, Trade and Industry data. Asian gasoil traders have previously said that gasoil production volumes from Japan could undergo declines over the coming months, as domestic refiners gradually switch to maximizing jet/kerosene fuel for the peak winter demand period. This, combined with the recent news of refinery outages in Japan, could mean even tighter regional gasoil balances ahead for the middle distillate as it heads into Q4, a seasonally strong period for the product.
The Asian gasoil market has been experiencing strong upward momentum since August, driven primarily by restricted supply availabilities from Japan, South Korea and China, which have come even as regional demand has been robust.
In early October, the outright price of 10 ppm sulfur gasoil cargoes for loading from Singapore pushed through the psychologically important $100/b mark for the first time in nearly four years, fueled by a rally in crude as well as strong demand for gasoil. This was borne out by a firming gasoil/Dubai crack, which reflected the relative strength in the market.
While the momentum in the Asian gasoil market appeared to slow down towards the end of last week, traders attributed the ease back to the market going through a period of normalization following the strong run-up in values, and said they believed that the Asian gasoil complex remained fundamentally strong moving forward into Q4.
At the Asian close Monday, the cash differential for FOB Singapore 10 ppm sulfur gasoil was assessed at plus 65 cents/b to MOPS Gasoil assessments, up 8 cents/b from Friday, while the front-month November/December gasoil timespread was up 5 cents/b to plus 63 cents/b.
The U.S. and China seemed like a good match, at least in terms of liquefied natural gas supply and demand. Beijing was determined to clean up its smoggy air by shifting away from coal, and America had LNG to sell.
Then the trade war broke out.
The tariff battle has touched off a domino effect in the energy industry, with major geopolitical implications far beyond the world's two biggest economies.
China became the second-largest importer of LNG last year, after Japan, and in doing so shipped in 500% more of the fuel from the U.S. The volume exceeded 100 billion cu. feet, accounting for under 10% of China's total purchases, and the ratio was expected to rise further.
After U.S. President Donald Trump imposed a third round of tariffs against China on Sept. 24, however, the Chinese side hit back the same day with levies on $60 billion worth of American goods. The retaliation included a 10% tariff on LNG.
This has sparked nervousness on the street. "I'll be in trouble if the price of natural gas goes up due to the trade war," said a taxi driver in the Chinese city of Chongqing. Roughly 100,000 taxis and other vehicles in the city run on natural gas.
But Beijing does have options. It is deepening ties with a pair of countries also at odds with the White House -- Russia and Iran. Meanwhile, faced with the prospect of losing its lucrative foothold in China, the U.S. is pushing hard to sell more gas to Europe and Japan.
The new reality crystallized in September, at the Eastern Economic Forum in Vladivostok. Russian President Vladimir Putin described Chinese President Xi Jinping, who was attending the event for the first time, as the most important guest. In a show of camaraderie, the two leaders dined on Russian crepes together.
Their talks reportedly covered expanded cooperation in energy, including natural gas.
Also at the forum, state-owned China National Petroleum Corp. and Russian gas producer Novatek discussed LNG projects in the Arctic Ocean. A number of such endeavors are underway in the frigid region, and funds from China are crucial.
Yet another key project is the Power of Siberia pipeline for transporting gas from a field in eastern Siberia to China. Construction was delayed from the original plan, as China was counting on LNG from the U.S., but the momentum appears to be picking up again.
"We must complete negotiations on additional supplies before the end of this year and, before Dec. 20 next year, launch deliveries through the Power of Siberia pipeline," Russian Deputy Prime Minister Dmitry Kozak said on Sept. 17.
Chinese President Xi Jinping and his Russian host, President Vladimir Putin, show camaraderie over crepes on the sidelines of the 2018 Eastern Economic Forum in Vladivostok in September.
As for Iran -- like Russia, a target of U.S. economic sanctions -- CNPC has taken over French oil giant Total's rights to part of the development of the South Pars field in the Persian Gulf, the Islamic Republic News Agency reported in August.
The field is one of the world's largest, and Iran ranks No. 1 globally in proven natural gas reserves. This does not mean the gas can be exported immediately, but the arrangement should help China prepare for a future demand surge.
Beijing's next move could be to procure gas produced in Iran and Turkmenistan through a pipeline.
China is reportedly thinking about joining a pipeline project involving Turkmenistan, Afghanistan, Pakistan and India, known as TAPI. In August, Pakistani media quoted Mobin Saulat, the chief executive of Pakistan's Inter State Gas Systems, as saying that China has expressed interest in TAPI as a complement to the Belt and Road Initiative.
For other gas producers, China is simply too large to ignore. In the coming years, the country looks destined to become the world's biggest market.
Qatar's state-owned LNG producer, Qatargas, announced on Sept. 10 that it had sealed a contract to provide PetroChina with 3.4 million tons of LNG annually for 22 years. At the end of that month, state oil company Qatar Petroleum unveiled a plan to raise its LNG production capacity to 110 million tons a year, from 77 million tons.
Australia and Canada are also eyeing opportunities in the Chinese market.
None of this bodes well for the U.S. energy industry. The trade war could undermine American competitiveness and boost projects in places like Canada, Russia and Qatar, according to Samuel Phillips of Barclays. Production and export of LNG requires massive capital investment in lengthy construction projects, and the tit-for-tat tariffs mean China is less likely to invest in U.S. developments.
Pessimism was running high at a conference hosted by the United States Association for Energy Economics, a nonprofit organization, in Virginia at the end of September. Many participants questioned the prospects for LNG initiatives in the U.S.
"For the long-term market, the consequences are likely to be felt on new supply developments," said Giles Farrer, research director at Wood Mackenzie, an energy research and consulting company. The trade war "restricts the target market for developers of new U.S. LNG projects trying to sign new long-term contracts."
Large LNG projects, worth around $60 billion, have been planned in Texas and other parts of the U.S. in anticipation of increased demand from China. Their fate is unclear.
The irony is that Trump sees energy exports as an effective tool to reduce America's trade deficits with other countries.
The shale gas revolution transformed the U.S. into a natural gas exporter. And last year, China was the No. 3 buyer of U.S. LNG after Mexico and South Korea, taking in 15% of the total exports.
As China looks elsewhere, Trump is desperate to fill the void quickly, partly to protect American energy jobs. This is where Europe and Japan come in: They appear to be making concessions on LNG to keep Trump's anger over trade imbalances at bay.
"If you look at the miners in coal, if you look at energy, LNG -- Japan just gave us some numbers that are incredible," Trump said after a summit with Japanese Prime Minister Shinzo Abe in New York on Sept. 26. "They're doubling the amount that they are going to be buying for Japan."
Boasting of his deal-making prowess, the president added: "I said, 'You have to do me a favor. We don't want these big deficits. You're going to have to buy more.'"
Japanese trading house Sumitomo Corp. in September entered into discussions on procuring more LNG from Texas. A company operating a processing facility in the state plans to turn out about 2 million tons of LNG per year for Sumitomo, over a 20-year period starting in 2023. The plan is to use a new plant currently under construction.
The shale gas revolution turned the U.S. into a natural gas exporter, but the trade war is seen as a threat to the industry's competitiveness. © Reuters
Earlier, in July, Trump met with European Commission President Jean-Claude Juncker and agreed to start negotiations on boosting exports of U.S. LNG to the European Union. Then, in September, German Economy Minister Peter Altmaier announced that the site for a new LNG import terminal would be decided by the end of the year as "a gesture to our American friends."
The upshot? As more countries gain ground as gas suppliers and emerging economies become bigger consumers, the energy market of tomorrow may look nothing like it did yesterday.
"The impact on the value might be limited for now," said Dave Ernsberger of S&P Global Platts. "But there is the potential to completely re-engineer the flow of the world because of this trade war."
U.S. Energy Secretary Rick Perry met his Russian counterpart, Alexander Novak, last month and told him that while competition is welcome, Moscow can no longer use energy as a weapon because the U.S. is now positioned as an alternative supplier to Europe and Asia.
But energy is never far removed from geopolitics. According to Reuters and other media, China completely stopped importing crude oil from the U.S. in September. And as the trade war rages, natural gas, too, is becoming a more prominent form of diplomatic ammunition.
https://asia.nikkei.com/Spotlight/Asia-Insight/US-China-trade-war-weaponizes-liquefied-natural-gas
Japan’s Tokyo Gas has signed a heads of agreement for the supply of liquefied natural gas from LNG Canada project with Diamond Gas International, a Mitsubishi Corporation unit.
The Shell-led LNG project in which Mitsubishi Corporation holds 15 percent interest, is expected to produce 14 million tons per annum (mtpa) of LNG by liquefying natural gas from reserves in Western Canada at an LNG liquefaction plant to be built in Kitimat.
Of all the volumes to be produced at the project, DGI will offtake 2.1 mtpa, and Tokyo Gas said it will purchase up to 0.6 mtpa of LNG on a delivered ex-ship basis.
The contract has a 13-year term and is set to start in April 2026, and last through to March 2039.
Tokyo Gas added the contract has no fixed destination clause allowing for delivery flexibility.
https://www.lngworldnews.com/tokyo-gas-snaps-up-lng-canada-volumes/
Toho Gas inks LNG Canada supply deal
zoomImage courtesy of LNG Canada
Japanese utility, Toho Gas on Wednesday signed a deal with Diamond Gas International for the supply of liquefied natural gas from the recently sanctioned LNG Canada project in Kitimat, Canada.
Diamond Gas International, a Mitsubishi Corp unit, will deliver up to four cargoes or about 300,000 tons of LNG per year to Toho Gas.
The contract has a 15-year term and deliveries are set to start in 2024/2025, on an ex-ship basis, Toho Gas said in its statement.
The company added that further to its current supplies from Indonesia, Australia, Malaysia, Qatar and Russia, it plans on starting LNG imports from the United States in the fiscal year 2019.
The Hague-based LNG giant Shell has taken a final investment decision on LNG Canada earlier this month. Other project partners include Malaysia’s Petronas, PetroChina, Japan’s Mitsubishi Corporation and Kogas of South Korea.
LNG Canada will initially export LNG from two trains totaling 14 million tons per annum (mtpa), with the potential to expand to four trains in the future.
The joint venture of JGC-Fluor Corporation has been previously selected as the project’s engineering, procurement and construction (EPC) contractor.
https://www.lngworldnews.com/toho-gas-inks-lng-canada-supply-deal/
Naphtha cracks in Asia and Europe plunged Tuesday as both regions struggled to offload excess barrels amid lackluster demand.
In Asia, the H1 December CFR Japan naphtha physical crack against front-month ICE Brent crude futures retreated $8.225/mt on the day to $81.20/mt on Wednesday's Asian close, the lowest level in three months.
The second-line trading cycle was last lower at $77.375/mt on July 3.
Fundamentals on the Asian naphtha complex continued to regress from oversupply and tepid demand as the market backpedalled into a contango structure, ending two weeks of backwardation.
The spread between benchmark CFR Japan naphtha physical first-line and third-line trading cycles -- currently H2 November versus H2 December laycans -- went deeper into negative terrain, down 50 cents/mt to minus $2.50/mt Wednesday, reflecting weakness that could extend into December.
The oversupply situation could extend further into December-delivery laycans as the digestion of surplus materials has been slow, with arbitrage naphtha cargoes for November arrival into Asia likely to be rolled over into December, market sources say.
In the West, the front-month CIF NWE cargo naphtha crack was also lower, falling to minus $5.10/b Tuesday, the lowest point since August 30, 2016. That weakness was also reflected in the paper structure in Europe, as the contango at the front of the curve steepened, with October weakening to a $1.75/mt discount to November.
That weakness was due not only to a weakening gasoline market, but also lingering oversupply of cargoes from the US through September and into October, sources said, while regional demand and an open arbitrage from the Med to the East has remained insufficient to cut back the overhang.
Tepid blending demand and well-covered petrochemical buyers, who have also benefited from competitive propane prices, has left the market struggling to find buying interest in recent weeks, according to sources.
However, product has continued to flow East, sources said, pushed in particular by the weakness in Europe.
Natural gas prices have spiked over the last few weeks as U.S. inventories run low ahead of the peak winter heating season.
Nymex natural gas prices have jumped nearly 15 percent over the past month, rising to roughly $3.30 per million Btu (MMBtu). The market has clearly grown a little concerned about adequate supplies heading into the winter and that is reflected in natural gas prices rising to their highest point since the beginning of the year.
For the week ending on September 28, natural gas inventories stood at 2,866 billion cubic feet (Bcf), or 636 Bcf lower than at the same point a year earlier, as well as 607 Bcf below the five-year average.
Inventories dropped to extraordinarily low levels last winter as much of North America became enveloped in exceptionally cold weather. As tens of millions of people cranked up the heat, the U.S. burned through record levels of natural gas. That stood in stark contrast to the year earlier, when a much milder winter led to above-average levels of gas in storage.
Natural gas markets are cyclical, with a buildup in storage between April and November – the so-called “injection season” – and steep drawdowns during the winter. The stockpiling during injection season is necessary to provide enough supply to consumers for winter heating needs.
But the problem is that the U.S. is currently on track to finish up the injection season with the lowest level of gas sitting in storage in 13 years. Even though demand sees seasonal peaks and valleys, consumption is rising on a structural basis as more coal plants shut down and more gas is exported in the form of LNG.Related: The Overlooked Giant In Renewables
That trajectory has been clear for much of 2018, but up until only recently, traders were not concerned about shortages. Natural gas production continues to soar, and several new pipelines in the Appalachia region are expected to unlock new markets, allowing drillers to produce eve more natural gas. For example, just days ago, the Atlantic Sunrise pipeline came online, connecting more Marcellus shale gas to the U.S. south. Investors saw this as a boon to natural gas drillers – Cabot Oil & Gas saw its share price jump on the news since it can now ship more gas out of the Marcellus.
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In short, despite low inventories, traders have not been concerned about the natural gas supply/demand balance heading into winter. That is, until recently.
Record power burn over the last few weeks from unseasonably high temperatures put more strain on inventories. According to S&P Global Platts, U.S. gas demand has averaged 72.5 Bcf/d since September 1, up 9 percent over the same period last year. Adding to the market pressure is a series of nuclear outages, pushing more gas-fired power plants into service. Overall, U.S. power burn is at a record high so far in October.Related: Goldman: The Oil Market Can Handle Iran Outages
Compounding matters, temperatures in the U.S. Midwest and Northeast are about to plunge, dropping from the mid-80s F in many places down to the mid-50s F or even mid-40s F. It’s almost as if we are going to flip directly from summer to winter, bypassing the low-demand period of autumn. The pressure on supply does not bode well since we haven’t even entered the drawdown season yet.
Nevertheless, this does not mean that a price spike is inevitable. “Because the factors that drove cash market strength over the past month – namely, a very warm September and multi-year highs in nuclear outages – are temporary, we believe cash prices will come back down to earth once these fundamental supports wear off,” Barclays analysts wrote in an October 4 note. “We remain bearish versus NYMEX futures, but we have raised our 4Q18 and 2019 forecasts to $2.95 and $2.72, respectively, to reflect lower storage.”
However, the investment bank acknowledged that with inventories at their lowest level in more than a decade, the market has “very little cushion to withstand weather demand swings,” leaving pricing risk skewed to the upside. Volatility is on the rise and the market will “balance on a knife’s edge in almost any weather scenario,” the bank concluded.
https://oilprice.com/Energy/Gas-Prices/Prices-Soar-As-Natural-Gas-Inventories-Hit-Decade-Low.html
Energy major Shell has announced plans to produce more gas from its QGC joint venture, in the Western Downs region of Queensland.
Under the Goog-a-binge project, Shell will progressively drill 250 new wells during 2019 and 2020, which will connect the existing QGC gas processing plants and bring about 930 PJ of gas to market over the next three decades.
Shell Australia chairperson Zoe Yujnovich said on Tuesday that Project Goog-a-binge would further boost Queensland’s regional economy and demonstrated Shell’s commitment to bring more gas to market.
“Project Goog-a-binge will deliver more and cleaner energy for both our Australian and liquefied natural gas (LNG) export customers for decades,” Yujnovich said.
“The project is expected to create or sustain up to 350 jobs, the majority of which will be in regional Queensland and generate business opportunities for local suppliers – a substantial and ongoing boost for the local economy,” she said.
Queensland Mines Minister Dr Anthony Lynhamwelcomed the announcement, saying that the latest expansion plan would help ensure sustained gas supply to domestic customers, as well as royalties to fund frontline services across the state.
“Most importantly, it will pump millions of dollars into local household budgets, local stores and local businesses for the next 30 years.”
Queensland Resources Council (QRC) CEO Ian Macfarlane applauded Shell for its continued support of the Queensland gas industry.
“More gas being produced is good news for all gas customers, both domestic and export. With a go-slow on gas development in New South Wales, and a blanket ban on some types of gas projects in Victoria, what the Southern states are really saying is they’re not prepared to support local jobs and local industry.
“Queensland is putting up its hand for more investment made possible by a strong resources industry that creates jobs, supports regional communities and has paid A$387-million in agreements with landholders,” Macfarlane said.
QGC will start pre-construction and site preparation activities at some sites next month, with wells to start being drilled from January 2019 through to December 2019, subject to government approvals.
http://www.miningweekly.com/article/shell-to-drill-250-new-wells-at-queensland-venture-2018-10-10
Brazil’s state-controlled oil company Petroleo Brasileiro SA is forming a joint venture with Murphy Oil Company to explore oil and gas fields in the Gulf of Mexico, the Brazilian company said on Wednesday in a securities filing.
According to the filing, Petrobras, as the Brazilian company is known, will have a 20 percent stake in the joint venture, and Murphy will have 80 percent. Petrobras will receive $1.1 billion in the transaction, the filing added.
Both companies will contribute with all their producing assets in the Gulf of Mexico for the joint venture. The joint venture will have a production of 75,000 barrels of oil equivalent per day during the fourth quarter, according to the filing.
The deal is one of the few Petrobras has been able to pull off since Supreme Court justice Ricardo Lewandowski decided in June that all sales of subsidiaries should go through the Congress. The company is far from reaching its goal of selling $21 billion in assets in 2017 and 2018.
The giant gas field offshore Vietnam is near waters claimed by China, presenting significant geopolitical risks to its development
Beijing is closely watching progress on the ExxonMobil-led Blue Whale gas development offshore Vietnam, as the project is near waters claimed by China in the South China Sea.
Although the giant field, which holds an estimated 150 billion cubic metres of gas reserves, does not technically fall within China’s controversial ‘nine-dash line’, drilling carried out by Exxon will drain the same basin China was exploring in 2014 with its Haiyang Shiyou 981 drilling unit. And this could trigger Beijing’s ire.
http://interfaxenergy.com/gasdaily/article/32863/exxonmobil-could-spark-chinese-fury-over-blue-whale
Coal’s push to $100 a ton in Europe may benefit the greenest energy providers more than it does for miners.
Companies that provide alternatives ranging from renewable power plants to natural gas turbines are expecting a lift after the commodity reached a five-year high. Far from spurring a revival of the dirtiest fossil fuel, executives of energy companies that provide an alternative expect the move to accelerate a shift toward cleaner power sources.
Higher energy costs also put efficiency on the agenda of industry and policy makers, breathing life into technologies designed to squeeze more out of raw materials of all kinds.
“It’s an opportunity,’’ Paolo Bertuzzi, chief executive officer of Turboden SpA, a unit of Mitsubishi Heavy Industries Ltd., said at the Bloomberg NEF summit in London. “What’s important is not just the price but also the trend. If prices are rising, people start to think more about what to do about energy costs.’’
The surge in coal stems from record demand for energy in China, which has driven up the cost of power generation fuels of all kinds. That’s drawn cargoes away from Europe and boosted electricity prices from Britain to Italy.
Those governments already were working to limit fossil fuel emissions to rein in climate change. As a result, many utilities have spent years re-positioning to draw supplies from wind and solar farms instead of coal plants.
Higher coal and power prices make renewables look like a better economic bet against fossil fuels, according to Ignacio Galan, CEO of Iberdrola SA, which was the first big promoters of wind power in Europe.
“Fossil fuel costs are increasing, and that’s helping renewable energy,’’ Galan said in an interview at the BNEF conference in London this week. “It signals that if you invest in fossil fuel sources, you will be penalized.”
Clean vs Coal
Energias de Portugal SA made similar moves and largely draws its electricity from renewables. It expects to benefit from higher power prices and demand — and it has fewer coal plants to feed than competitors such as Uniper SE and RWE AG.
“The fundamentals on the power sector are going in the right direction,” said EDP’s CEO Antonio Mexia. “Demand is growing, so frankly for us, especially for our portfolio, this is good news. It makes me more optimistic about the future.”
Policy makers are taking note of the higher prices too. In Ukraine, which gets a third of its electricity from coal, the government is seeking alternatives such as nuclear and natural gas as a fuel for industry. Much of its coal is imported, since Ukraine’s mines were largely destroyed in its conflict with Russia.
“Making coal great again is actually being paid for by the Ukraine,” said Dan Bilak, chief investment adviser to the nation’s prime minister. “The price of coal is going to compel us to invest in other sectors.”
By contrast, higher coal prices will discourage companies from building more plants that use the fuel, said Gonzalo Garcia, co-head of the global natural resources group in the investment banking division at Goldman Sachs Group Inc. “There’s no new coal being built in western Europe, and probably not in the U.S. Renewables are clearly going to be the largest share of the electricity market.’’
For now, higher coal prices don’t mean a boom in mining for the biggest producers. Anglo American Plc and BHP Billiton Ltd. have said they won’t spend money on new coal mines, Rio Tinto Plc has sold out of coal while Glencore Plc is philosophically opposed to building any new mines at all.
Oil companies also expect to benefit from rising coal costs, since natural gas they supply is used as a competing power generation fuel.
“The coal price increase has an impact and it is very good news for renewables, and very good news also for gas, and also very good news for CO2 emissions,” said Philippe Sauquet, president of gas, renewables and power at the French oil major Total SA. “If coal is expensive, less coal will be dispatched, there will be more room for gas and the CO2 emissions will decrease.”
Turboden, which makes turbines that recycle waste heat into electricity, also expects to benefit. It built a 2-megawatt unit for a Heidelberg Cement AG factory in Morocco that since 2010 has been drawing energy from the exhaust gasses at the plant to spin a power turbine. Four years ago, the project started producing additional electricity from a concentrated solar-thermal plant near the site.
“If conventional fuel costs increase and you’re offering energy efficiency, then the payback time for those projects is shorter and they become more attractive,” Bertuzzi said, anticipating sales across the Middle East, Africa and Russia.
https://www.hellenicshippingnews.com/coal-reaching-100-a-ton-in-europe-boosts-greener-alternatives/
Texas energy companies are pouring millions of dollars into Washington state to fight a ballot measure that, if passed, would create the nation’s first carbon fee, raising the cost of gasoline and other fossil fuels and likely hurting demand for petroleum products.
The fee, essentially a tax on carbon emissions, is considered by environmentalists, economists and even some oil companies as a market-based approach to slowing the pace of climate change by providing incentives to use energy sources that produce less carbon dioxide, a greenhouse gas that traps the sun’s heat and contributes to global warming. Fossil fuels, such as coal, oil and natural gas, are among the largest sources of carbon dioxide emissions.
Washington’s proposed carbon fee, which voters will be asked to approve in November, would impose a fee of $15 a ton on carbon emissions starting in 2020, and increase by $2 a ton a year in the subsequent years. The state estimates the carbon fee would raise upwards of $2.3 billion in the first five years, with 70 percent of the money spent on developing renewable energy, 25 percent to respond to effects of climate change such as rising sea levels, and 5 percent five percent toward reducing the impact of climate change on the most vulnerable communities, such as those at risk from from wildfires.
The campaign over Initiative 1631 could be a gauge of public concern over climate change and willingness to adopt policies aimed at reducing the use of fossil fuel — even if it means higher energy costs, analysts said. Washington voters will consider the ballot question following a summer of wildfires that destroyed wide swaths of California and deadly flooding in North Carolina caused by Hurricane Florence — natural disasters blamed in part on warming global and ocean temperatures.
If the initiative passes, it could provide the impetus for carbon fees or taxes across the country, said Aseem Prakash, a University of Washington political science professor and founding director of the Center for Environmental Politics at the University of Washington.
“If the yes people succeed here,” Prakash said, “then first of all, it will demonstrate that there’s popular support and second, it will give an empirical basis to claim that a carbon tax or a carbon fee actually does not hurt economic growth.”
In Washington, refiners and transportation fuels would bear the brunt of the carbon fee, which would raise the price of gasoline by 14 cents a gallon and cost a two driver household and additional $167 a year, according to an analysis by the Washington Policy Center, a think tank that promotes free-market solutions. Companies such as Phillips 66 of Houston and the British oil major BP — both which operate refineries in the state — have contributed nearly $19 million to the campaign to defeat the proposal.
The companies argue that the carbon fee would be ineffective because the proposal excludes some large carbon polluters that are considered energy intensive and compete in global markets, a definition that could include pulp and paper manufacturers, maritime companies and the aircraft maker Boeing, one of the state’s biggest employers. The initiative also exempts a coal-fired power plant near Centralia,Wash. until it shuts down in 2025.
“We agree that there’s a carbon mechanism that can be put in place but it’s got to be fair,” Bieber said. “It can’t exempt the largest polluters, it can’t unfairly put the burden on families and consumers and it’s got to provide some assurances that carbon emissions will, in fact, be reduced.”
But perhaps the biggest concern among energy companies is that the initiative would open the door for states to adopt their own brands of carbon taxes or fees, creating a maze of varying systems and costly administrative nightmare for companies trying to comply with 50 different versions of a carbon charge. BP, for example, has joined other oil companies, such as Exxon Mobil, that have called on Congress to adopt a national carbon tax that would be the same in all states.
“BP supports a well-designed price on carbon that is clear, flexible, efficient and can be applied consistently across the economy,” the company said in a statement.
At least 10 states, including Washington, have considered carbon taxes and fees, although none have to yet to pass them, according to the New York research firm Rhodium Group. Internationally, several European countries and Canadian provinces have adopted carbon taxes of some sort.
The idea behind carbon taxes and fees is simple. By raising the costs of fuels that emit carbon dioxide, consumers and businesses will turn to alternatives, creating bigger markets for electric cars or solar and wind power and encouraging investment in cleaner forms of energy that ultimately reduce greenhouse gases.
This is not the first time that Washington voters have considered a carbon tax or fee. In 2016, a carbon tax proposal, Initiative 732, was rejected decisively, with nearly 60 percent of voters opposing the measure.
Supporters of the initiatives say this time is different because Initiative 1631 earmarks money raised from carbon fees for specific measures to shrink the carbon footprint of power generation, such as investing in renewable energy, and help communities cope with the effects of climate change. The state has suffered at least five wildfires that each burned more than 100,000 acres in the last five years, according to data from the National Interagency Fire Center, a support center for wildland firefighting based in Boise, Idaho. In 2015, the state, well known for its rain, was gripped with extreme drought conditions.
“What 1631 does is it identifies a future in which Washingtonians have more choices,” said Mike Stevens, the Washington state director for the Nature Conservancy, a national environmental advocacy group. “We will be stimulating investments in new and emerging technologies that are cleaner and sustainable and profitable for Washington businesses.”
The Nature Conservancy is the largest donor to the Yes on 1631 campaign, contributing more than $1.2 million. The Yes campaign has raised more than $6.5 million.
That pales in comparison to the money raised for the No campaign. Phillips 66 and BP, which each have refineries in the state, contributed $7.2 million and $6.4 million, respectively. Before its merger with Marathon Petroleum of Ohio, the San Antonio refiner Andeavor, which also operated a refinery in the state, contributed $4.3 million.
Valero recently gave $495,000 to No campaign. Koch Industries, run by the influential backer of conservative causes, Charles Koch, recently contributed $300,000.
President Donald Trump said on Friday there was a shortfall in the U.S. defence industrial base relating to lithium sea-water batteries and the Defense Department would purchase equipment for pilot production of the batteries that are critical for anti-submarine warfare.
A Pentagon-led report issued on Friday that seeks to mend weaknesses in core U.S. industries vital to national security included recommendations such as expanding direct investment in sectors deemed critical.
The White House said on Friday that it would expand “direct investment in the industrial base to address critical bottlenecks, support fragile suppliers.”
A senior U.S. administration official said new steps to ensure U.S. military’s supplies include an effort to build up stockpiled reserves of scarce materials and expand U.S. capabilities to manufacture products such as lithium sea-water batteries.
In letters to heads of the House of Representatives Financial Services Committee and the Senate Banking Committee, Trump said initiatives to develop lithium sea-water batteries and alane fuel cells are “essential to the national defence.”
He said the Defence Department would develop and purchase equipment and materials for pilot production of the batteries and fuel cells.
U.S. President Donald Trump is expected to announce the lifting of a federal ban on summer sales of higher-ethanol blends of gasoline on Tuesday in Washington DC ahead of a trip to Iowa the same day, according to two sources familiar with the planning of the event.
The move, expected sometime around 3 p.m. on Tuesday, is aimed at helping Republicans in competitive elections in the nation’s farm belt. Iowa is the largest U.S. producer of ethanol.
The lifting of the summer ban on so-called E15 gasoline is expected to be coupled with restrictions on trading biofuel credits that underpin the program, the sources said, but it’s unclear whether the restrictions will be detailed or left up to the U.S. Environmental Protection Agency to decide.
The American Petroleum Institute, the largest U.S. oil group, opposes lifting the ban, which will eat into the industry’s market share of gasoline sales. The move also faces bipartisan opposition in congress.
The U.S. Renewable Fuel Standard requires refiners to blend increasing amounts of biofuels like ethanol into the fuel pool each year, or buy credits from competitors who do. Refining companies that must buy the credits have complained about volatile prices in recent years.
The summer ban was put in place as an anti-smog measure, though studies have since shown its environmental benefits are limited. Trump will direct EPA to write a rule lifting the ban, and it would have to be fast-tracked to have it finalized before the next summer driving season.
Albemarle Corp fell on Monday following news that Chile’s nuclear regulator refused to increase the company’s quota to sell lithium produced from its Salar de Atacama operation.
The Chilean Nuclear Energy Commission (CCHEN) rejected Albemarle’s March request to increase its quota to sell lithium products by 258,446 tonnes, according to a Sept. 13 agency resolution obtained by Reuters via a Chilean freedom of information request.
Albemarle spokeswoman Andrea Cole said CCHEN’s concerns are of a “technical nature” and that the company would re-submit its request “in the coming weeks,” hoping to resolve the issue.
Shares of the world’s largest lithium producer, based in Charlotte, North Carolina, pared losses and closed down 0.8 percent at $102.25.
CCHEN oversees the sale and export of lithium from Chile, though not production, which is controlled by a separate state agency.
The setback could represent a major blow to Albemarle, which aims to satisfy spiking global demand for the ultralight metal used in batteries that power products ranging from cell phones to electric vehicles.
Albemarle previously said that it could achieve an increase in production using more efficient technology, and without extracting any more lithium-rich brine, or saltwater, from the environmentally sensitive Atacama salt flats.
But Chile’s nuclear agency said in the September resolution that Albemarle had failed to answer more detailed questions about how the “technology would permit the increase in efficiency.”
Cole, in an emailed statement, said Albemarle was confident the increase would be approved, “as it entails a project that presents a breakthrough technology to produce more lithium without using more brine.”
Cole added that the company believes its existing sales authorizations are sufficient.
The filing does not indicate the timeframe for the sales quota increase, although lithium companies typically seek decades-long quotas and contracts.
The request came as Albemarle has publicly touted an increase in allowed output to 145,000 metric tons of lithium carbonate equivalent annually through 2043 from Chile’s Economic Development Agency (Corfo), which oversees lithium production in the Salar de Atacama.
The reason for the discrepancy in the physical amount of lithium between the two requests to the two different agencies was not immediately clear.
Corfo declined to comment on CCHEN’s decision.
In Chile, CCHEN’s control over lithium exports dates back to the dictatorship of Augusto Pinochet, which declared lithium “strategic” for its value in nuclear production processes.
Eurasian Resources Group (ERG) plans to ramp up cobalt output at its Democratic Republic of Congo (DRC) facility as it expects the electric car industry to boost demand for the metal, ERG Chief Executive Benedikt Sobotka told Reuters.
ERG, a global mining and metals group with Kazakh roots, aims to raise cobalt output fivefold to 20,000 tonnes next year, claiming a large chunk of the booming market whose volume was around 100,000 tonnes in 2017, Sobotka said in an interview in Moscow.
The growth is expected to come from the launch of the Metalkol facility in DRC where ERG will reprocess cobalt and copper tailings - waste dumped by other miners.
ERG believes Metalkol will become one of the world’s biggest cobalt producers with output capacity of 24,000 tonnes of cobalt and 120,000 tonnes of copper cathode.
The DRC government this year enacted a new mining code, which imposes a windfall profits tax, raises royalties and cancels so-called stability clauses that had protected miners against changes to the fiscal regime for 10 years.
Major mining companies such as Glencore and Randgold have opposed the code, saying the tax hikes and the removal of exemptions for pre-existing operations were a breach of their agreements with the government.
But Sobotka indicated ERG, which posted a core profit of more than $2 billion in 2017 and expects to boost that number this year on record output at all units, was committed to its DRC operations.
“If you want to be a cobalt market player, DRC is the place to be. It has 70 percent of global (cobalt) reserves,” Sobotka said.
ORGANIC GROWTH
Cobalt is a key ingredient in the lithium-ion batteries essential for electric energy storage, and the DRC produces more than half of the world’s supply.
ERG has two other copper and cobalt mining units in DRC and owns a smelter in neighboring Zambia which refines both metals. This year, it will produce 4,000 tonnes of cobalt and 150,000 tonnes of copper.
Next year, output is set to grow to 20,000 tonnes and 230,000 tonnes respectively, Sobotka said.
He said growth in the electric car industry would reshape demand for cobalt, lithium, copper and aluminium in coming years, and ERG planned to increase its output accordingly.
“Our plan is to boost cobalt capacity to 50,000 tonnes and copper to over 350,000 tonnes,” Sobotka said.
He provided no details of the expansion plans, but said ERG, in which the Kazakh government owns a 40 percent stake, aimed for organic growth and the development of its own projects.
The group’s cobalt output will mostly come in hydroxide form, which is used to produce batteries for electric cars and electronic devices.
Congolese cobalt, however, faces another problem aside from increased taxes - some consumers are concerned about the use of child labor at the country’s artisanal mines.
The London Metal Exchange said last week it was preparing plans that will allow it to clamp down swiftly on cobalt brands on its approved list thought to be tainted by human rights abuses.
To address the issue, ERG plans to use a blockchain-based tracking system that would guarantee the “ethical purity” of its cobalt, Sobotka said.
Chinese lithium and cobalt prices have started to lose some of their sheen as capacity bottlenecks ease, said SMM general manager, Ian Roper. "Lithium prices in particular should see more downside near term as new processing capacity continues to be added.”
Speaking to delegates at the LME week in London, he said that lithium saw tight supplies last year, but bottlenecks have eased. Oversupply of lithium carbonate exerted pressure on lithium prices. "As lithium battery manufacturers have been destocking since the fourth quarter of 2017, lithium carbonate prices have dropped", he added.
SMM assessments showed that prices of battery-grade domestic lithium carbonate averaged 79,000 yuan/mt as of Tuesday October 9, down over 50% from 164,000 yuan/mt at the beginning of the year. Prices of battery-grade domestic lithium hydroxide declined some 12.5% and averaged 130,000 yuan/mt as of October 9.
In the first half of 2018, China imported 96,000 mt of LCE (lithium carbonate equivalent), up 73% year on year, SMM data showed. This grew LCE inventories by over 60,000 mt.
As more processing capacity comes online in the fourth quarter, hydroxide prices are likely to follow carbonate prices lower given current processing costs of some 10,000 yuan/mt.
Chinese cobalt prices declined from May. SMM believes that cobalt prices will fluctuate between 300-400 yuan/kg. "We see the market being well supplied into next year, with no major structural deficit until 2020," Roper said.
On electric vehicles (EV), Roper believes that policy direction remains the key driver for China’s EV development.
Denmark-based offshore wind energy developer Ørsted announced it will pay $510 million to acquire Deepwater Wind, the Providence, R.I., company that has the Block Island Wind Farm and half a dozen offshore wind plays off the U.S. East Coast.
“The two companies’ offshore wind assets and organizations will be merged into the leading US offshore wind platform with the most comprehensive geographic coverage and the largest pipeline of development capacity,” Ørsted and Deepwater officials said in a joint statement Monday.
China’s top lithium producer Ganfeng Lithium tumbled as much 28 percent on its Hong Kong debut, a stark warning sign to fellow Shenzhen-listed counterpart Tianqi Lithium which is also planning a listing in the city.
Shares of Ganfeng, a supplier to carmakers like Tesla and BMW, fell to a low of HK$11.80 in early morning trading after opening at HK$15.30 on Thursday.
That was well below its offer price of HK$16.50, which was already at the bottom of the stock’s indicative range.
Ganfeng’s listing came as world markets slid to a 3-month low on Wednesday, while Hong Kong’s benchmark Hang Seng index is down 20 percent from its January highs.
Although demand for lithium is expected to rise as electric cars become more mainstream, an oversupply of the metal has weighed on prices, causing them to drop as much as 38 percent this year.
Ganfeng recently signed contracts with Tesla and BMW to supply lithium components to their battery suppliers. Lithium is a key ingredient in rechargeable batteries.
The company raised $421 million in its Hong Kong listing and could raise as much as $448 million if a greenshoe, or over-allotment, option is exercised within one month of the start of trading.
Ganfeng’s shares in Shenzhen had already slumped 10 percent on Wednesday, making it the worst performer on the China Securities Index 300 Materials Index.
The company made a net profit of 478.7 million yuan ($69.08 million) in the second quarter of this year, up 33 percent from the first quarter. Its 2017 revenue jumped 54 percent to 4.38 billion yuan from 2016.
Ganfeng plans to use the proceeds from its Hong Kong listing to acquire lithium resources and expand its production capacity of lithium metals, batteries, compounds and recycling.
The controlling shareholder in Chilean lithium producer SQM on Wednesday filed suit with Chile’s Constitutional Court to block a deal allowing the sale of nearly one-fourth of the miner to China’s Tianqi Lithium Corp.
The lawsuit alleges that Chile’s antitrust court last week failed to follow due process when it approved a settlement between Tianqi and Chilean regulators allowing the Chinese miner to purchase a coveted 24 percent stake in the world’s No. 2 producer of lithium. The court said the agreement would limit the exchange of commercially sensitive information between the two companies.
But Pampa Calichera, Potasios de Chile and Global Mining - which together control a majority stake in SQM - allege the five-member court had approved the deal “practically in secret.”
“The opportunity given to my clients to learn, understand and then opine on a deal worth more than $4 billion, which generates enormous competitive risks for SQM, was five days, and nothing more,” lawyers for the shareholders wrote in the lawsuit.
The three shareholders, known collectively as the Pampa Group and controlled by SQM’s former president, Julio Ponce, asked the court to “urgently suspend” the agreement between regulators and Tianqi.
Tianqi did not immediately reply to requests for comment.
Tianqi’s interest in acquiring the stake in SQM comes as Beijing is aggressively promoting electric vehicles to combat air pollution and help China’s domestic carmakers leapfrog the combustion engine to build global brands.
The agreement between Chile’s antitrust regulator and Tianqi stipulates that the Chinese miner cannot name any of its executives or employees to SQM’s board, and requires it notify regulators of any future, lithium-related deal struck with either SQM or rival and top lithium producer Albemarle.
Prior to its approval, SQM had objected to the deal on the grounds it did not go far enough to limit Tianqi’s access to corporate secrets and sensitive information.
Chile’s antitrust regulator launched an investigation in June, shortly after Tianqi said it would buy 24 percent of SQM for $4.1 billion, giving it a stake in one of the world’s top producers of lithium, a key ingredient in the batteries that power everything from cellphones to electric vehicles.
China expects to reduce cost for solar power generation by further 30% in the coming three years, following notable decreases in recent years
Three months after deployment, the world’s first floating wind farm surpassed performance expectations, according to its operator, Statoil. The five-turbine, 30-MW Hywind Scotland Pilot Park — situated 15 miles off the Aberdeenshire Coast — operated at 65% of its maximum theoretical capacity last November, December, and January, the Norwegian energy company said.
Each of the five floating wind turbines at Hywind Scotland Pilot Park is capable of pumping 6 MW of energy into the grid for a project total of 30 MW of generating capacity. When not used, power is stored in lithium batteries for later use. Watch the full story of Hywind’s development at tinyurl.com/FloatingHywind (Source: Equinor | Statoil)
By comparison, the typical capacity factor during the winter season for a bottom-fixed offshore wind farm is 45 to 60%. The 65% capacity figure was achieved despite a hurricane and a severe winter storm with wave heights up to 27 feet.
Hywind’s turbines are about 830 feet tall, 256 ft of which is submerged beneath the water’s surface. Each massive tower is tethered to the bottom of the sea by floating chains, weighing in at 1,323 tons. The floating turbines, in waters more than 328 feet deep, theoretically could generate enough electricity to power 20,000 average UK homes when operating at full capacity.
The offshore advantage
The main advantage of a floating wind farm is that offshore wind speeds are typically faster than on land. Small increases in speed result in large increases in energy production. For example, a turbine in a 15-mph wind can generate double the energy as one in a 12-mph wind, according to the American Geosciences Institute. In addition, offshore wind speeds are steadier than those on land, producing a more stable source of power. Considering that coastal areas constitute half of the U.S. population, these benefits offer the opportunity to serve power-dense regions.
The disadvantages of building offshore include potential turbine damage from severe offshore storms, the high costs of construction, and the challenge of building reliable wind farms in deep waters.
To date, floating turbines have been deployed only in modest projects, such as the 7-MW system built and operated by the Fukushima Wind Offshore Consortium off the coast of Fukushima Prefecture, Japan. Typically, offshore wind farms are built on sea beds in shallow waters. However, 80% of the offshore wind resources are in water that is too deep (200 ft.) for conventional bottom-fixed wind turbines, according to a Statoil spokesperson.
“We expect to see exponential growth in floating offshore wind worldwide,” Statoil said, particularly as technology matures and costs drop. “We are on the outlook for new regions, and are evaluating several interesting areas where there is a potential for floating offshore wind. Of high-potential markets, we believe in Japan, the west coast of North America, and even Europe as a few examples.” These are areas where sea beds drop steeply off the coast.
Toyota not only believes that electric vehicles are hindered by the amount of cobalt that’s available, but also that democratizing hybrids is better for air quality.
Toyota, the quintessential brand that brought electrified vehicles to life with the Prius, has, interestingly and somewhat confusingly, decided against fully-electric cars. One would think that Toyota, with its rich history of making hybrids, would be one of the first to introduce an electric vehicle. That hasn't been the case, though, as Toyota, unlike other automakers, has shied away from EVs.
Toyota Sticks To Hybrids
Earlier this May, Toyota announced that it would continue to choose hybrids over pure electric cars over the next 10 years. Toyota's general manager of its powertrain division, Shinzuou Abe, pointed toward the high costs, weight, size, and deterioration of batteries in electric cars as the reason for the automaker continuing to avoid battery-powered vehicles like the plague.
Electric vehicles were a large part of the Paris Motor Show, and while other global brands were showing off new cars with electric powertrains, Toyota stood its ground, sticking with its decision to not go down the battery rabbit hole. Top Gear got to speak with Gerald Killmann, one of Toyota's engineers in Europe, who reaffirmed the brand's position.
Killmann provided the same insight on electric vehicles as Abe did before, explaining how the global shortage of batteries doesn't make sense to chase electric cars. "We see hybrid lasting a long time if the shortage of battery manufacturing carries on like today," Killmann told the outlet.
The engineer also put out a philosophical question for the longevity of hybrids: "Say you have 40 kWh cells. Do you put them into one EV and leave 39 other cars as pure internal-combustion, or do you make 40 hybrids, which have roughly 1 kWh of battery each?
Why Are Electric Vehicles Unattractive To Toyota?
That's an interesting dilemma that we haven't heard yet. Some brands haven't even considered hybrids, only developing fully-electric cars as a way to meet emissions and fuel economy standards. EVs are expensive to develop and manufacture, but a lot of automakers believe the high costs are worth it, as the powertrains are seen as the future.
For Toyota, hybrids are the future, and it has something to do with air quality. "Our research shows that in European cities, hybrids are running in zero-emission mode with the engine off for two-thirds of the time and half the distance they drive," said Killmann. "So if we made 40 hybrids instead of one EV we have caused half the miles to be zero-emission. If we made one EV, only one fortieth of the city miles would be zero-emission. That's why it's better for air quality to democratize the hybrid."
Lithium-ion batteries are expensive and hard to come by at the moment, and the demand for the component is expected to double by 2024. That means automakers will have to make tough decisions in the future, which include deciding to make multiple electrified offerings, like hybrids and plug-in hybrids, or one electric vehicle.
Then, there's the industry's move toward solid-state batteries, Killmann points out. While everyone's scrambling to make lithium-ion batteries, in spite of all of the supply shortages involving cobalt, lithium, and nickel, solid-state batteries are on the horizon and will require a lot of money and development on the parts of automakers. It doesn't make financial sense, at least for Toyota, to chase lithium-ion batteries at the moment with solid-state batteries right on the horizon.
If you're waiting to purchase a fully-electric vehicle from Toyota, you'll be waiting for quite some time. But the Japanese brand still has plans to introduce new hybrids, like the Corolla Hybrid, Camry Hybrid, RAV4 Hybrid (pictured), and Lexus UX Hybrid, which all were at the Paris Motor Show.
http://www.futurecar.com/2722/Toyota-Continues-to-Back-Hybrids-Believes-EV-Batteries-Are-Flawed
Solar power projects in the northwest Chinese region of Ningxia are struggling to maintain operations and face “bankruptcy risks” because of long subsidy payment delays, according to an investigation by regulators.
The warning follows rapid growth in China’s solar sector, which has led to a subsidy backlog of 120 billion yuan ($17.4 billion), with prices for solar power varying wildly from region to region.
China wants to bring down renewable energy costs to allow wind and solar projects to compete subsidy-free with coal-fired power. It has already capped the number of new projects this year in a bid to ease its subsidy burden and help the sector focus on efficient supply.
The National Energy Administration’s (NEA’s) bureau in charge of northwest China said the payment backlog had forced many Ningxia projects to take high-interest loans to stay afloat, with some unable to afford basic maintenance.
Government-approved solar projects are entitled to a subsidy for each kilowatt-hour they sell to the grid, but the surge in new capacity has left the finance ministry struggling to make the payments on time.
“Local authorities in Ningxia should further control the capacity of renewable projects and strengthen supervision of subsidy distribution... in order to prevent widespread bankruptcy in the industry,” said the report.
Some Chinese regions have already achieved “grid-price parity”, and according to draft rules published earlier this year, the government will work to provide more support for subsidy-free projects.
However, wind and solar projects in western regions like Ningxia and Xinjiang still find it difficult to compete with cheaper coal, even though grid firms are legally obliged to source as much power from renewable sources as they can.
The regulator admitted solar and wind power generation and transmission projects in Ningxia were “very expensive”, with data earlier this week showing the grid in Ningxia paid just 255.5 yuan per megawatt-hour (MWh) for coal-fired power last year, compared to 871.6 yuan for solar.
A recent warming of the Pacific Ocean has led to a 70 percent chance of an El Nino weather event developing this year, Australia’s Bureau of Meteorology said on Tuesday.
An El Nino weather event can trigger both floods and drought in different parts of the world, and is associated with warmer, dry weather across the Asia Pacific.
El Ninos are particularly damaging to Australia, with the last one in 2015/16 cutting agricultural production in the country - among the world’s largest exporters.
The weather outlook comes at a time when dry conditions have wilted crops and pasture in Australia’s each coast, leaving many farmers struggling to survive.
“There is an increased possibility of a dry and warm end to the year. It also raises the risk of heat waves and bushfire weather in the south, but reduces the risk of tropical cyclone activity in the north,” Australia’s Bureau of Meteorology said in an emailed statement.
Bayer AG’s Monsanto unit received a tentative ruling for a new trial on the $250 million in punitive damages awarded by a jury to a groundskeeper who alleged the company’s glyphosate-based weed killers, including Roundup, caused his cancer.
According to a Wednesday court filing in San Francisco’s Superior Court of California, Judge Suzanne Bolanos was considering whether to grant the company’s motion for a new trial on the punitive damages.
The judge’s ruling, granting a new trial on the punitive damages, is tentative and was being discussed at a court hearing underway on Wednesday. The Aug. 10 award to Dewayne Johnson included $39 million in compensatory damages.
The combined $289 million verdict marked the first decision finding that Monsanto had failed to warn consumers of the alleged cancer risks posed by glyphosate, the world’s most widely used weed-killer.
Bayer, which bought Monsanto earlier this year for $63 billion, faces more than 8,000 similar lawsuits in the United States.
Plaintiff Dewayne Johnson leaves the courtroom following a post-trial hearing at the Superior Court in San Francisco, California, U.S., October 10, 2018. REUTERS/Jim Christie
The German company has denied the allegation and has said that decades of real-world application and scientific studies have shown the chemical to be safe for human use.
Investors have raised concerns over the litigation risk, with Bayer shares falling sharply after the decision and still trading some 20 percent below their pre-verdict level at 75.10 euros ($86.57) on Wednesday.
In September 2017, the U.S. Environmental Protection Agency concluded a decades-long assessment of glyphosate risks and found that the chemical was not a likely carcinogen to humans. However, in 2015 the cancer unit of the World Health Organization classified glyphosate as “probably carcinogenic to humans.”
On Wednesday, the judge said that Johnson had failed to meet his burden of producing clear and convincing evidence of malice or oppression by Monsanto, a requirement for allowing a jury to award punitive damages.
Monsanto had asked Bolanos in court filings on Sept. 18 to set aside the entire verdict or, in the alternative, reduce the award or grant a new trial.
The judge’s order said the company’s request for an entire new trial that includes liability grounds would also be discussed during Wednesday’s court hearing.
Bayer did not immediately respond to a request for comment.
Lawyers for Johnson said they would only comment after Wednesday’s court hearing concludes.
Johnson’s case, filed in 2016, was fast-tracked for trial due to the severity of his non-Hodgkin’s lymphoma, a cancer of the lymph system, that he alleged was caused by years of exposure to Roundup and Ranger Pro, another Monsanto herbicide that contains glyphosate.
China’s soybean imports fell slightly in September from a year earlier but were ahead of market expectations, boosted by large volumes from Brazil as buyers tried to shore up stocks, customs data showed on Friday.
Soybean imports are being closely watched after Beijing in July imposed a 25 percent tariff on U.S. products worth $34 billion, including soybeans, in response to U.S. penalties on Chinese goods worth the same amount.
China, the world’s top soybean buyer, brought in 8.01 million tonnes of the oilseed in September, down from 9.15 million tonnes in August and below last year’s 8.11 million tonnes, according to Reuters calculations based on data released by the General Administration of Customs on Friday.
But the arrivals were higher than market expectations of over 7 million tonnes, said Monica Tu, analyst at Shanghai JC Intelligence Co Ltd.
A surge in purchasing from Brazil had caused backlogs at ports, delaying some arrivals in August. Those cargoes cleared customs the following month, which boosted September numbers, she said.
Chinese buyers have been scooping up Brazilian beans on worries of tight supplies of the oilseed in the fourth quarter when cargoes from the United States usually dominate the market.
Farmers have sold 92.9 percent of the old 2017/18 crop in Brazil, compared with 83.7 percent at the same time a year earlier, and 90.2 percent historically for the period, data showed.
The buying spree has pushed up prices of beans from the South American country, the world’s top exporter, even above the cost of U.S. shipments including the hefty tariffs.
Most Chinese buyers, however, still chose to stay away from U.S. cargoes because of the risk of further curbs on U.S. soybeans.
The customs data showed imports for the first nine months at 70.01 million tonnes, down from 71.45 million tonnes for the same period last year.
China’s soybean imports will further drop in the coming months as it enters what has typically been the major buying season for U.S. cargoes, possibly leading to a shortage of the oilseed, analysts said.
China is considering limiting the amount of protein used to feed pigs and poultry to cope with tighter soybean supplies in coming months.
The push is part of a broader strategy to wean the country off its heavy reliance on imports of the oilseed.
Spence Diamonds doesn’t believe that mined stones are a “superior choice” for all consumers. Their approach is to provide customers with the best possible educational and shopping experience, including all options that may be appropriate for them. (Image courtesy of Spence Diamonds.)
Lab-grown diamonds, made for decades as an inexpensive alternative to mined stones for industrial purposes, are cracking the consumer market largely thanks to millennials' evolving shopping tastes.
In a survey of 1,000 consumers aged between 21 and 40, half of which had household incomes of $50,000 or higher, nearly 70% said they would consider buying a lab-grown diamond for an engagement ring, MVI Marketing revealed earlier this year. That was a 13 percentage-point increase from the year before, when 57% said the same.
Many claim that despite lab-grown diamonds increasing popularity, mined ones remain a superior choice. But Eric Lindberg, executive chairman of Canada’s Spence Diamonds, disagrees.
From a physical properties standpoint there are no differences between mined and man-made diamonds, at least for the consumer.
“We think that it’s wrong to assume there’s one ‘superior choice’ for all consumers. Our approach, and what we hope more of the industry will adopt, is to be advocates for our customers and to provide them with the best possible educational and shopping experience, including all options that may be appropriate for them,” he told MINING.com.
Synthetic diamonds have the same physical and chemical features as mined stones. They’re made from a carbon seed placed in a microwave chamber and superheated into a glowing plasma ball. The process creates particles that can eventually crystallize into diamonds in just 10 weeks. The technology is so advanced that experts need a machine to distinguish between lab-made and mined gems.
“From a physical properties standpoint there are no differences, at least for the consumer, to the extent that the U.S. Federal Trade Commission recently ruled that earth-mined and lab-grown diamonds are identical,” Lindberg said.
Referring to mined diamonds as “natural” in the U.S., in fact, is now considered a deceptive trade practice because the term implies that created diamonds are somehow inferior, he noted.
Big names on board
The entry of new actors in the synthetic diamond market, particularly giant producer De Beers and its Lightbox brand, has created even greater awareness for lab diamonds and is spurring more consumer activity, according to Lindberg.
Eric Lindberg, executive chairman of Spence Diamonds (Image courtesy of Spence Diamonds.)
“For the time being, we don’t think that there will be any dramatic impact except for a possible negative impact on demand for lower-quality mined diamonds,” the expert said.
He also believes consumers will make their decisions based on many factors, not just pricing.
“We think it goes deeper than price – quality, ethics, and a belief in sustainable practices play a big part,” he noted.
Synthetic manufacturers have focused on the ethical reasons for opting for lab-grown diamonds, as the mining industry still struggles to keep “conflict diamonds” at bay.
“There is an important and growing segment of customers for whom this is critically important,” Lindberg said. “We have noted a rapidly growing number of customers who state that they are only shopping for one of our created diamonds.”
Yet, data from Morgan Stanley shows that sales of lab-grown diamonds make up just 1 percent of the $80 billion global business for rough diamonds.
Based on what Spence Diamonds has been hearing from its younger customers, Lindberg believes the mined industry needs to push aggressively to make further improvements and to pay attention to what organizations like Human Rights Watch are saying about ways the sector can be more transparent.
Not all lab-diamonds created equal
As with mined diamonds, there are many variables that impact the quality and price of a created diamond. “Ungraded lab-grown diamonds, like those in the Lightbox collection, are a different class than high-quality stones independently certified the way high-quality mined diamonds are,” Lindberg said.
Just like a mined stone, he notes that each created diamond is unique, based on tiny fluctuations in the conditions under which it was made, including whether the manufacturer uses renewable energy sources and ethical employment practices.
Chile’s Supreme Court upheld an environmental order for a gold mine owned by Canada’s Kinross Gold Corp to close its water pumping wells, the environmental regulator said on Wednesday, bringing the curtain down on a long-running dispute that sparked the Toronto-based miner’s retreat from Chile.
The environmental watchdog, known locally as the SMA, initially ordered that the wells serving the Maricunga mine be shut down in 2016. The ruling was challenged by Kinross in Chile’s environmental tribunal and then in the country’s highest court.
The Supreme Court on Wednesday backed the original order, pointing to the “inadequate management of unforeseen environmental impacts on the Pantanillo-Ciénaga Redonda basin,” which is located in northern Chile’s Atacama Desert.
Kinross told Reuters it was analyzing the decision’s implications on potential future operations at the mine.
“Mining at Maricunga was suspended in Q4 2016 and the decision is not expected to impact the status quo,” a spokeswoman said.
Kinross, the world’s fourth largest gold miner by output in 2017, halted all extraction, grinding and stockpiling of ore in the fourth quarter of 2016 and laid off 300 staff after the original ruling in March of that year.
At the time, local news media quoted the company as saying that environmental damage in the area had been caused by drought rather than extraction operations.
The Maricunga mine accounted for 8 percent of the company’s total gold production in 2015.
Norsk Hydro has been granted a permit in Brazil to use new technology to extend the life of a disposal area for its troubled Alunorte alumina refinery, the world’s largest, which should lead to the restart of operations at 50 percent, the firm said on Saturday.
The decision came on Friday, two days after Hydro said it would halt production and layoff 4,700 people at Brazil’s Alunorte, which has been operating at half capacity since March due to an environmental dispute.
“Hydro’s alumina refinery Alunorte was granted an exceptional authorization... which will extend the life of its DRS1 bauxite residue disposal area and allow Alunorte to continue operations on safe conditions,” it said in a statement.
The authorization was granted by Brazil’s federal environmental agency IBAMA and it allows the utilization of a press filter technology that provides stackable residues with considerably less water content than the drum filter.
Hydro will now work with Brazil’s Secretary of State for Environment and Sustainability (SEMAS) to get a second authorization that will permit the use of the technology in Alunorte’s DRS1 bauxite residue disposal area.
“After receiving this (second) authorization, Alunorte will be able to re-start the operation at 50 percent of capacity,” said the firm.
Resuming 50 percent production at Alunorte would also allow Hydro’s bauxite mine Paragominas and its joint-venture primary aluminium smelter Albras to continue operating at half capacity, rather than being shut down, its Bauxite and Alumina head, John Thuestad, said.
Three days ago, when Hydro said it would halt production at Alunorte, shares fell 12 percent to a 21-month low, making it the worst performer in the European STOXX 600 Index. The price of aluminum, the product made from alumina, climbed 5.5 percent to its highest since June.
Closures of Alunorte, Paragominas and Albras would have “significant operational and financial consequences” Hydro said at the time.
The decision to halt all production had been taken as the refinery’s waste deposit area is close to full capacity due to an embargo on the new press filter and as an ongoing dispute with Brazil’s authorities had been preventing Hydro from using a newly created residue facility, the firm said on Wednesday.
On Thursday, a day after Hydro’s decision to halt operations at Alunorte, the Brazilian state of Para said it was surprised with the move and asked for a report explaining the decision.
Alunorte made 6.4 million tonnes of alumina in 2017, about 10 percent of global production outside China and enough to make some 3 million tonnes of aluminium. Its partial shutdown earlier this year drove up market prices for alumina and aluminium.
With a resolution to Freeport-McMoRan’s Indonesian saga in sight, CEO Richard Adkerson says any strategic move is now possible, including acquisitions, partnerships, or even a sale of the entire company.
Freeport is planning to remain an independent entity, Adkerson said Thursday in a wide-ranging, 90-minute phone interview. “But if an opportunity for us to sell to another company would arise, and that would be good for our shareholders, you would see us trying to get the best deal we can get as opposed to being a company where management is trying to protect itself.”
Freeport has been engrossed in intensive negotiations with Indonesia to cede majority control of its flagship Grasberg mine to local interests for almost two years. With a package of agreements close to being sealed, “the future, strategically for us, is going to be wide open,” Adkerson said. “We have enormous resources.”
One possibility is acquisitions. While he wouldn’t rule that out, Adkerson said they are harder to justify than spending to expand the company’s existing portfolio of mining assets. “I would argue that we’re getting virtually no value at our share price today from our resources,” he said.
Adkerson has previously highlighted the potential to expand its Lone Star operation in eastern Arizona, and to further develop resources in South America. However, copper prices need to be above $3 a pound for the industry to invest in brownfield development, and Freeport is no exception. The world’s largest publicly traded copper producer won’t pull the trigger on new projects until market uncertainties are resolved, Adkerson said, noting that while copper fundamentals are strong, global trade tensions are weighing on prices.
Despite that, he said the Phoenix-based company has never been afraid to make big purchases that make sense. “We stepped up and did the Phelps Dodge deal when nobody else was willing to,” he said. “That was two and a half times our size.”
Freeport also is regularly approached by companies about partnerships, he said, and maintains a good relationship with London-based Rio Tinto Group, which agreed to sell its full stake at Grasberg as part of the broader deal that saw majority ownership of the asset transferred to local interests.
‘I UNDERSTAND’
“They’re very interested in looking for opportunities to partner with us, as is everybody in the global copper industry, including Chinese companies,” Adkerson said of Rio. Rio’s decision to sell Grasberg was a “strategic” move made during a time of great uncertainty in which they were faced with a requirement to divest 50% of the asset, he said. “I understand why they made the decision.”
Rio declined to comment.
Vancouver-based Teck Resources has said it’s looking for a partner for its Quebrada Blanca Phase 2 expansion project in northern Chile. “We’re following it and I don’t think it’s appropriate to comment more than that,” Adkerson said. “Teck’s a company that we have a great relationship with, and it’s an interesting project.”
Partnerships with Chinese companies are also an option. A number of Chinese companies are already Freeport’s customers through its sale of copper concentrates, he said. Executives also got to know management at China Molybdenum Co. during the latter’s purchase of Freeport’s stake in the Tenke Fungurume mine in Democratic Republic of Congo, as well as other Chinese companies that were interested in the mine. Freeport also has a “great relationship” with Japan’s Sumitomo Corp., which controls 28 percent of the Morenci copper mine in Arizona, he said.
NOT IN THE CARDS
Chinese companies have been actively acquiring mines around the world. Asked if any have approached Freeport in recent years about a possible takeover, Adkerson said a tie-up would be unlikely to be approved by US regulators, who see copper as a strategic metal. “We supply a third to 40% of the copper to US industry, and so I don’t think it would be in the cards, politically in the United States, for a Chinese company to buy Freeport as a corporation, and they all recognize that.”
Freeport hasn’t been directly impacted by US-China tensions, Adkerson said, because anything it sells to China is produced outside the US and it doesn’t import copper products from the Asian country. The trade war only affects Freeport insofar as it influences the global economy, he said.
‘PURPOSE IN LIFE’
Under Adkerson’s watch, Freeport has had its ups and downs, including a “value-destructive” purchase of energy assets in 2014, according to Chris Mancini, an analyst at Gabelli & Co.
“He’s kind of endured the company’s darkest hours and now they can see some light,” Mancini said by phone. “If the Grasberg deal gets finalized, then the ship has been righted.”
At that point, one of the biggest questions for Freeport becomes how long Adkerson, 71, will stay at the helm. Given the years of negotiations in Indonesia and a massive deleveraging effort after the commodities downturn, it’s been a tough road, Adkerson acknowledges. “I’ve learned the difference between purpose in life and enjoyment because not all of this has been enjoyable.”
That said, he remains in good health, has no immediate intention to retire, and is looking forward to speaking more often with investors and analysts. In the meantime, Freeport is making plans for succession, he said.
“That could happen in several ways, in terms of having some ongoing involvement,” Adkerson said. “But there’s nothing right now except to focus on business at hand.”
India's product has generally not been regarded as high enough quality by Japan's demanding buyers, who have preferred top-tier producers like Rio Tinto, Alcoa and South32 as well as United Company Rusal.
However, imports of aluminium ingot from India doubled in the first eight months of 2018 from a year ago, Japanese trade data shows, while imports of alloy - which include higher-value products - surged 11-fold off a tiny base.
"Because of the sanctions, consumers would like to ensure some security of supply, so they'd like to prefer multiple suppliers instead of one supplier," Samir Cairae, chief executive of Vedanta's diversified metals business in India, told Reuters.
The increased trade is a blow to Rusal, the world's second-biggest aluminium maker, which accounted for about 20 percent of Japan's imports of both aluminium ingot and alloy in 2017, but which has been hit by US sanctions.
Customers globally have had to scramble to find alternative sources of metal even after the United States eased sanctions restrictions for some customers, and they were likely to permanently diversify supply chains, said a source at a Japanese trading house.
"Many of their customers are reluctant to order the same amount of supplies that they have bought in past years for next year even if the US sanctions are lifted," the trader said.
Japanese trading houses such as Mitsubishi Corp have been aggressively importing supplies from India as well as other countries to help customers diversify supply, trading sources said. Mitsubishi declined to comment.
Products from India are mainly refined ingots rather than value-added products such as billets and slabs, said a second trading house source. Substitute material for Rusal's higher quality products has come from the Middle East and Malaysia.
However, Indian metal was winning growing acceptance and was also being sold at a discount to traditional suppliers.
"Japanese buyers are getting Indian metal for cheap," the source said.
IMPORTS SWELL
Japan took 59 545 t of aluminium ingot in the eight months to March, double a year ago, while material from Russia fell 21 pct to 175 694 t, Japanese trade data showed.
Imports of aluminium alloy from India jumped to 3,008 tonnes over the same period, while Russian imports fell 10 percent to 185 685 t.
The US trade actions - 10% import tariffs on the light metal from March and sanctions against Rusal from April - sent shockwaves through the market, boosting aluminium prices to seven-year highs and pushing up costs to obtain physical metal in the US domestic market.
"Stronger US premiums have become incentives for smelters in Australia, which is exempted from the duties, to ship more products to the US," said a third trader, who saw Indian products filling the supply gap left by Rusal in Asia.
Vedanta, India's largest producer of aluminium, sees a big opportunity in Asia including Japan and Korea.
Cairae said the company is focusing on ramping up exports of its value-added products such as billets, which can be used in the transport, construction and packaging industries, and wire rods.
Hindalco did not immediately respond to a request for comment.
President Donald Trump’s attempt to wield U.S. economic strength as a weapon against foreign adversaries is being tested as the Treasury Department struggles to contain the fallout from its sanctions against the world’s second-largest aluminium producer.
The financial penalties imposed on Russia’s United Co. Rusal in April were intended to punish its majority owner, billionaire Oleg Deripaska, as well as Russian President Vladimir Putin.
But global aluminium prices shot up as much as 20 percent in the first week the sanctions were announced, throwing the global market into chaos that’s since continued, threatening a worldwide shortage of the metal, and forcing Treasury Secretary Steven Mnuchin to backtrack.
Rusal is among the largest companies the U.S. has ever put on its sanctions designation list. The value of the aluminium producer has plummeted to $4.15 billion as of Oct. 5 from $9.2 billion a little more than six months ago. In general, Trump has made unprecedented use of financial levers to pressure countries including North Korea, Iran and even NATO ally Turkey. Sanctions designations jumped 30 percent in 2017 compared to former President Barack Obama’s final year in office, according to the law firm Gibson Dunn.
Sanctions are a valuable tool for U.S. presidents, essentially allowing them to take on adversaries without resorting to actual bloodshed. But the Rusal penalties have caused such widespread pain that Mnuchin may be forced to holster what’s become one of Trump’s favorite weapons in his global economic war.
“The rapid growth in sanctions is giving rise to an equally rapid rise in costs and unintended consequences,” said Peter Harrell, a fellow at the Center for New American Security, a Washington-based research group, and a former Obama administration State Department official. “The U.S.’s aggressive use of sanctions may finally spur allies and major companies to develop alternatives to the U.S. financial system that gives our sanctions enormous global weight.”
The European Union in September announced a plan with Russia and China to sidestep U.S. sanctions on Iran by using a payment system separate from the dollar to give oil buyers a way to buy Iranian crude, which Trump will block in November. The creation of a trade channel outside the U.S. financial system would soften the sanctions’ bite and make it easier for Iran to continue selling its oil.
Venezuela, meanwhile, whose economy the U.S. has helped cripple through sanctions intended to target government corruption, has created a cryptocurrency called Petro, backed by the country’s oil reserves, as a way to avoid using the dollar.
In both cases, the nations’ ability to maintain trade flows while not using the U.S. currency is unclear.
Negotiations Since April
Aluminium markets are now focused on the Treasury Department’s Office of Foreign Assets Control, which implements sanctions, as investors and customers wait for a decision on Rusal. Treasury has been in negotiations since April with Rusal’s parent company, En+ Group Plc, on what it would take to lift the restrictions on the companies. Over the past six months, OFAC has slowly extended the deadline to comply. Each extension has brought relief to aluminium markets, with the first one in April trimming prices nearly 10 percent.
Critics say the large market swings are proof that Treasury went after a target that was too big. As customers rushed to halt dealings with the world’s second-largest aluminium supplier, workers at Rusal facilities across western Europe wondered about their job prospects. Disruptions in supplies of a metal used in everything from aircraft to computers to power lines threatened to ripple across other economic sectors.
Steadfast Defence
But Treasury officials have been steadfast in their defence of taking on Rusal. Mnuchin has said repeatedly that the impact, however large, was expected, and that the goal was not to put the company out of business.
“The U.S. government is able to unleash incredibly powerful sanctions, and can do so confident in the knowledge that as additional information comes in, they can ameliorate the impact of those sanctions on U.S. and third-country businesses,” said John Smith, who was director of OFAC at the time the sanctions on Rusal were announced. He left in May.
Deripaska has paid a price for the sanctions. Since the April 6 announcement, the Russian’s wealth has dropped 59 percent to $3.1 billion, according to the Bloomberg Billionaires Index.
OFAC’s next step is expected in November. It again extended the deadline for cutting ties with companies controlled by Deripaska until just after the U.S. midterm elections, delaying a clash with Congress over the handling of sanctions against Russia.
Deripaska’s companies have approached Treasury about substantial changes that it signaled could lead to being removed from the sanctions list, a move that would be a tough sell to Congress, where lawmakers are eager to go harder on Russia. Treasury may also need Congress’ approval to lift sanctions related to Deripaska.
Treasury is “in a very tough position,” said Dan Fried, who previously served as a coordinator for sanctions policy at the State Department. Europeans companies are agitating to ease sanctions on Rusal because of the impact on the aluminum market, while many U.S. lawmakers argue Mnuchin is going too easy on Russia.
Lawmakers in both parties are considering stiff automatic sanctions, including on new issuance of Russian sovereign debt and the nation’s energy sector. Republican Senator John Kennedy of Louisiana has gone so far as to ask Treasury how Russia’s economy can be “brought to its knees” through sanctions. And Treasury officials have promised more penalties on Russia.
Codelco is in talks to sell up to 60,000 tonnes of copper a year to China Minmetals from 2019 to 2021, marking a change in sales strategy at Chile’s state-owned miner which typically made deals on an annual basis, industry sources said.
Sources say the aim was to agree “evergreen” three-year deals in which the Chinese company would commit to buy 50,000 to 60,000 tonnes a year of copper for the period.
Under the arrangement, the three-year pact would be rolled over annually, so from 2020 the deal would be extended to run for three years until the end of 2022 and so on.
The deal with China Minmetals, part of Codelco’s efforts to secure longer term supply contracts, focuses on the quantity of copper to be supplied, sources said.
Typically supply contracts are agreed annually for the next year during what is known as “mating season” in October and November when producers and customers agree quantities. Premiums are set above the London Metal Exchange benchmark price.
“Codelco is looking to establish a base of bigger and long term strategic customers worldwide and Asia is not an exception,” one of the sources told Reuters.
A Codelco official said the company did not comment on negotiations with customers. A China Minmetals spokesman said the company could not immediately comment.
“The relationship between Minmetals and Codelco has been there for many years, the important thing is the three years and the quantity,” a copper industry source said.
Codelco, the world’s largest copper miner, accounted for 1.734 million tonnes of global supplies last year, about 7 percent of the total estimated at about 23 million tonnes. It has historically been used as a benchmark for copper premiums.
Many companies are keen to lock in long-term supplies due to expectations of shortages over coming years, created by a dearth of new projects, deteriorating ore grade and healthy demand.
Sources say companies seeking to buy copper at the moment can easily find sellers and any deficits in the short term would see prices rise, which would see more scrap heading for the market to close the gap.
However, a 25 percent duty on Chinese imports of U.S. copper scrap imposed since from Aug. 23 has fuelled uncertainty about supplies in China, the world’s largest consumer of the metal used widely in power and construction.
“These tariffs have the potential to create a lot of problems for Chinese consumers. But it’s not just the tariffs, some companies just want to be sure they have supplies secured,” another copper industry source said.
“People think you can’t agree contracts without premiums, but premiums can be agreed at a later time,” the source added.
For 2019, Codelco has agreed some deals with premiums at $98 for European customers. Some Chinese customers have agreed to pay $88 a tonne and other Asian clients have agreed $83 a tonne.
Copper prices on the LME CMCU3 at around $6,200 a tonne are down more than 15 percent since early June, but up from the 14-month low of $5,773 a tonne hit on Aug. 15.
A poll conducted during LME week in London on Monday October 8 showed that nickel was the base metal with the greatest potential for 2019, garnering 39% of votes.
Copper, with 26% of votes, was runner-up.
German aluminium producer Trimet Aluminium expects strong aluminium demand in 2019 but the global impact of U.S. import duties makes forecasts difficult, said executive board member Thomas Reuther.
Trimet has not imported aluminium scrap from the United States, he said, despite some market expectations of more U.S. sales to Europe to replace lost exports to China. High alumina prices are a concern.
“I expect global demand for aluminium to increase in 2019,” Reuther said in an interview during the LME week. “But the customs duties first imposed by the U.S. are having an impact on trade flows, so demand in regional markets is more difficult to forecast.”
The United States imposed import tariffs of 10 percent on EU and Chinese aluminium in March. U.S. sanctions have also been imposed on Russian aluminium producer Rusal which meant an important aluminium oxide supplier for Trimet’s aluminium smelters was no longer available.
Trimet said it has mostly been able to safeguard supplies of aluminium oxide for its production sites.
“It is very important for the production of aluminium in Europe and worldwide that a positive and dependable agreement is reached about the U.S. sanctions on Rusal,” Reuther said.
“The current situation with temporary solutions brings uncertainty into an already volatile market.”
Whether full production in the coming year can be achieved could depend on whether “the relationship between raw materials prices and aluminium prices again normalizes,” he added.
TRADE WAR
The global aluminium industry has been troubled by rising alumina prices partly because of a production stop at Brazil’s Alunorte alumina refinery, the world’s largest.
“The aluminia price is unusually high at the moment because of several factors,” he said. “But this is not reflected in the aluminium price. As long as this continues, this could hinder the full use of production capacity. But we expect the situation to normalise in a few months.”
China’s imports of U.S. aluminium scrap are falling following the trade war between the two countries, generating speculation that more U.S. scrap would be sold in Europe. China’s imports of aluminium scrap are also being reduced because of the impact of its new environmental protection control standards which took effect in March.
Supplies in scrap are relatively high, with or without additional U.S. scrap being available, he said. “Scrap imports from the United States have not increased,” Reuther said. “We have not purchased scrap from the United States in the past and are currently not doing so.”
“We do not rule this out, but there are currently no grounds to do this.”
Trimet’s German plants produced some 625,000 tonnes of primary and recycled aluminium in its 2017/18 financial year ending on June 30, the same as the previous year and around full capacity. Trimet France produced an unchanged 140,000 tonnes of primary aluminium, he said.
“Automobile construction provides the main engine for demand growth,” he said. “Electro-mobility is providing additional momentum.”
“Demand in the energy sector is also growing. We expect stable demand from construction and packaging.”
Rising industrial demand in China and declining mining output will help support copper prices next year, CRU Group research analyst Vanessa Davidson said Monday.
During a presentation at the LME Seminar, held annually in conjunction with LME Week, Davidson said she expected global copper demand to grow 2.9% next year. Historically, copper demand grows about 2% each year.
Demand is being driven by China, which is trying to move away from investment-led growth to more consumer-led growth. Davidson said.
Demand from most end-use sectors in China is expected to remain firm, resulting in copper demand growth of about 3.5% next year, she said.
Tightness in copper scrap supply is also expected to boost Chinese demand for refined copper next year, she added. China severely restricted the flow of copper scrap imports this year after implementing import bans on “Category 7” waste material early in the year.
Copper prices are also likely to be supported by declining mine output, Davidson said.
Global mine output is expected to grow only 1.2% next year compared with about 1.8% this year, she said. “The key factor behind that is a lack of new projects,” she said.
No large-scale projects above 100,000 mt/year came online last year and the only such project to come online this year is Toquepala mine expansion in Peru, she said.
“We don’t have a growth from new projects coming in 2019. There are some projects due to start up in 2019, but it’s important to note that the two largest ones — the Chiquicamata underground [Chile] and Grasberg block-cave [Indonesia] — are both replacement projects,” she noted.
However, refined output is expected to grow 2.9% next year, as evidenced by the declining supply of blister and concentrate. Chinese smelter and refined output is also expect to continue growing, Davidson said.
As a result, the global refined copper market is expected to end next year with a small surplus of about 100,000 mt, she said.
Taking into account those factors, CRU expects LME three-months copper prices to average $6,420/mt next year, Davidson said.
Infrastructure construction in China will accelerate in the second half of the year as Beijing has been loosening policies in the face of potential impact from the trade war, said SMM general manager, Ian Roper.
Speaking to delegates at the LME week in London on Monday October 8, he said that infrastructure investment was cut at the beginning of the year. But that "the Chinese government is clearly accelerating infrastructure spending in response to trade concerns" and that "financial tightening has clearly reversed amid trade pressures". This is likely to boost fixed asset investment (FAI) in the second half of the year.
"Financial conditions clearly eased in April however, and new lending has recovered somewhat, which bodes well for metals demand growth into year end," Roper said.
Policy has eased selectively, as Chinese President Xi Jinping is determined to introduce risk into the financial system, SHIBOR fell by 200 basis points. This reflected that liquidity conditions are much easier and thus supportive to growth
China will increase export tax rebates from November 1 and quicken export tax rebate payments to support foreign trade, the cabinet said on Monday. Officials also said that local governments will step up special bond issuance for shanty-town redevelopment.
Over the weekend, China's central bank announced a steep cut in the amount of cash that banks must hold as reserves, marking the fourth such cut this year. This move, effective from October 15, will inject 750 billion yuan ($109.2 billion) into the banking system with the cut, by releasing 1.2 trillion yuan in liquidity, with 450 billion yuan of that to offset maturing medium-term lending facility (MLF) loans.
Chinese aluminium exports are expected to surge in coming months and next year after Beijing boosted tax rebates as part of a package to soften the impact of a trade war with the United States, according to industry consultancy CRU.
High Chinese exports of metals such as aluminium and steel in recent years have spurred criticism by both the United States and Europe, and was one reason for the imposition of tariffs by Washington.
Last month, China increased its rebate on value added tax (VAT) for exports of semi-fabricated aluminium or semis to 16 percent from 13 percent, said senior analyst Greg Wittbecker of consultancy CRU.
That will increase exports of both legitimate semis as well as so-called “fake semis”, which have been transformed from primary metal just enough to escape China’s export tax on unwrought metal and instead qualify for a VAT tax rebate, he added.
Often these “fake semis” are later melted back into primary metal by the end user.
“We think exports of semis will rise significantly over the course of the year (2019) and fake semis alone could probably approach 800,000 tonnes,” he said at a presentation during industry gathering LME Week.
Even before the boost in the tax rebate, exports were rising since even at the 13 percent rebate level exports were profitable, said Wittbecker, who formerly worked for aluminium producer Alcoa Corp.
Fake semis have already been showing up in South Korea, Thailand and Malaysia, he added.
In August, Chinese exports of unwrought aluminium and aluminium products were 517,000 tonnes, up 26.1 percent compared to the same month last year.
BHP expects a plant at its Olympic Dam mine to restart this month following repairs and the company has found a way to deliver returns from the asset as part of a focus on maxmising productivity, its head of Australian operations said on Tuesday.
“The expectation remains that we’ll have that back up and running this month,” Mike Henry, president of operations, minerals Australia, said in an interview on the sidelines of LME Week, an industry gathering in London.
“We have identified a very credible route to growing the asset,” Henry said, adding the company was on track with a plan to seek board approval for “bite-sized chunks of capital (expenditure) with healthy returns”.
Henry said Olympic Dam, which contains uranium oxide, copper, gold and silver, was “a wonderful ore body”, but in the latest in a series of setbacks, BHP in August announced it had shut an acid plant following a boiler tube failure, disrupting copper processing. Underground mining at the site continued as normal.
The company’s CEO said at the time Olympic Dam was the only part of the business not delivering “an acceptable return on capital”.
In Brazil meanwhile, it is still too soon to say when BHP’s Samarco iron ore operations, a joint venture with Vale , will resume output following a dam burst in late 2015. Brazil says this was its worst environmental disaster.
“We’re not on the cusp of a restart let’s put it that way,” Henry said and listed everything that needed to happen first, including winning community support, securing permits, ironing out technical details, proving the asset is “financially attractive” and restructuring its debt.
BHP is also still resolving legal issues in Brazil. It has signed a deal with Brazilian authorities that resolves a 20 billion reais ($5.30 billion) lawsuit, but separately it has two years to reach a settlement over a 155 billion reais lawsuit.
The company also remains under pressure from activist investor Elliott Advisors, which has called for BHP to collapse its dual British-Australian structure.
Unilever executives last week scrapped plans to move the company headquarters from London to the Netherlands in the face of a shareholder revolt.
BHP’s Henry said BHP had never ruled out collapsing its dual structure and would continue to look at the possibility, but it had yet to be convinced it could be cost effective.
“One thing we would take away from the Unilever decision is making sure we’re soliciting views from the full group of shareholders,” Henry said.
Elliott Advisors had no comment on Tuesday.
Chile’s state-owned miner Codelco, the world’s largest copper producer, plans to raise up to $1 billion next year to help finance the overhaul of its existing mines, Chairman Juan Benavides said on Tuesday.
Benavides also said the company was looking at exploration projects in Brazil, Ecuador and Kazakhstan and that plans laid out more than two years ago to invest in Mongolia had been shelved for now.
Codelco has an ambitious investment program to cut costs and boost productivity at its Chilean mines at a cost of $40 billion over 10 years, as it seeks to maintain production despite rapidly falling ore grades at its deposits.
“We will issue a maximum of $1 billion of debt in 2019, we don’t know where yet. It will be where the best benefits are in terms of cost, flexibility and interest,” Benavides said, adding that much of the $40 billion would come from cash flow.
The miner raised $600 million this year in Taiwan by issuing a 30-year bond and Chile’s government has committed to give Codelco $1 billion for its investment program.
Codelco’s main focus over coming years will be on Chile and extending the life of its mines, which include Chuquicamata and El Teniente.
Earlier this year, Codelco announced a $4.881 billion investment to convert its open-cast Chuquicamata mine into an underground facility and extend its life by 50 years.
“Chuquicamata is on target, we will see it processing by the middle of next year, July probably. Initially it will produce 275,000 tonnes of copper a year and by 2025 we expect it to produce about 350,000 tonnes,” Benavides said.
Chuquicamata produced 330,900 tonnes of copper in 2017, out of Codelco’s total of 1.734 million tonnes.
About 60 percent of the $40 billion or about $24 billion is for structural projects to extend the life of mines. The other 40 percent is for projects that include improving smelter operations and renewing equipment and machinery.
Codelco has the capability, experience and know-how for the development of open-pit and underground mines around the world, Benavides said.
“We are exploring in Ecuador, Brazil and have an agreement to collaborate with Kazakhstan. Mongolia is something we looked at, but we’re not advancing that.”
The company expects to keep costs of production steady at around $2.20 a lb or about $4,850 a ton.
Chile aims to find new copper markets and expand its lithium industry as it seeks to shield its economy from a U.S-.China trade war, the mining minister of the world’s biggest copper producer said on Monday.
Baldo Prokurica also told Reuters the South American nation was considering further opening up its copper and lithium mining industry to foreign investors to capitalise on the demand for both metals from the growing electric vehicle industry.
“Chile is to electric vehicles what Saudi Arabia is to crude oil,” he said of his country, which sits on half the world’s lithium reserves.
“We are trying to further diversify our economy through the number and quality of trade agreements we have,” Prokurica said in an interview for the LME Week industry gathering in London.
As part of efforts to find new markets, he said Chile was examining its trade deal with India that he said was “quite basic but could include other products.”
Chile produces nearly a quarter of annual global copper output of around 23 million tonnes, leaving its economy vulnerable to any downturn in China, which consumes about half the world’s copper supplies. One of the metal’s main uses is in the construction industry.
Washington and Beijing have imposed tariffs worth billions of dollars on each other’s imports, raising the risk of a broader global economic slowdown and weighing on copper prices.
“Were it not for the trade war between the U.S. and China, we would have a much higher copper price,” Prokurica said.
Chile’s government is forecasting an average copper price of $3 a pound this year, down from a forecast $3.06 in April.
Copper was last quoted at $2.74 a pound, having fallen from a four-year high around $3.25 in May.
Prokurica said Chile was also considering opening its copper and lithium reserves to foreign investment as part of its “Plan B” to shore up its economy against a slowdown in China.
Chile has about 7.5 million tonnes of lithium reserves. Lithium is used to make the rechargeable batteries for electric vehicles.
The Paris-based International Energy Agency estimates that by 2030 there will be 125 million electric vehicles on the road, versus 3.1 million in 2017. That total could rise to 220 million if environmental policies become more ambitious.
Prokurica said standard combustion-engine vehicles use around 23 kgs of copper and virtually no lithium, while electric vehicles use over 80 kgs of copper, as well as lithium.
Global demand for refined zinc will exceed supply by 322,000 mt this year, and the supply gap will narrow to 72,000 mt in 2019, said the International Lead and Zinc Study Group (ILZSG) in a report this week.
Demand for refined zinc is expected to grow 0.4% to 13.74 million mt in 2018 and climb 1.1% to 13.88 million mt in 2019, ILZSG estimates.
The study group expects a deficit of 123,000 mt in the global refined lead market in 2018, but a surplus of 50,000 mt in 2019.
ILZSG expects global demand for refined lead to increase by 0.2% to 11.71 million mt this year and by 0.7% to 11.79 million mt next year.
Rio Tinto is close to restarting a sale process for some of its aluminium assets, including a plant in Iceland, which have been valued at around $350 million, two sources familiar with the matter said.
The assets include a 53 percent stake in a Dutch anode facility and 50 percent of the shares in a Swedish aluminium fluoride plant, which are ingredients in aluminium production, the sources added.
French investment bank Natixis has been helping Rio with the sale, one of the sources said.
Rio Tinto declined to comment and Natixis was not immediately available to comment.
Norwegian aluminium company Norsk Hydro pulled out of a previous plan to buy the assets in September, blaming a delay in getting European Commission approval for the deal.
Given Hydro’s already major position in the aluminium industry, the European Commission may have had competition concerns, industry sources said.
Iceland generates all its electricity from hydropower and geothermal energy and Rio’s aluminium plant could appeal to companies looking to make their output as green as possible.
Producing aluminium requires huge amounts of energy, meaning it is also more cost effective to use hydropower.
Rio Tinto Chief Executive Jean-Sebastien Jacques, who took charge in July 2016, is gradually selling all but the company’s best-performing units.
Rio agreed in January to sell an aluminium smelter in Dunkirk in France to Sanjeev Gupta’s Liberty House, which also bought the miner’s smelter in Lochaber, Scotland.
The entire aluminium supply chain has been hit this year by U.S. sanctions on Russian producer Rusal, an outage at Norsk Hydro’s plant in Brazil and a strike at Alcoa’s alumina refineries in Australia.
Benchmark aluminium prices on the London Metal Exchange have risen 21 percent since the start of the year.
Norway’s Norsk Hydro is focused on a return to full output at its Alunorte alumina refinery in Brazil and is not contemplating layoffs there, CEO Svein Richard Brandtzaeg told Reuters on Wednesday.
Hydro had said last week it would close down the world’s largest alumina refinery and lay off 4,700 workers as attempts to resolve an environmental dispute with Brazilian authorities faltered.
This week it announced it has been granted permits from the authorities to restart operations at half capacity.
“The way we are operating now requires more staffing. As long as we have a positive dialogue with the authorities we will keep the staffing. We believe the embargo will be lifted and then we need all our people,” Brandtzaeg told Reuters in a telephone interview.
Hydro was ordered by Brazilian regulators in February to slash output by half at the refinery after the company admitted making unlicensed emissions of untreated water during severe rains.
“It’s difficult to give exact timeline for a full restart but we are now in the process of implementing measures we agreed on with authorities in September,” he said.
The plant has an annual capacity of 6.4 million tonnes of alumina, or 10 percent of capacity outside China.
Alunorte transforms bauxite into alumina, which is turned into aluminium at huge smelters.
Alumina and aluminium prices have been pushed up by Hydro’s production cut at Alunorte. Brandtzaeg acknowledged it was unfortunate that Hydro one week announced plans for closure and the next week plans to recover output.
“We want stable and predictable operations, but in this case it was not possible,” he said.
Overall demand in the market was “quite good”, driven by auto industry and global GDP growth, Brandtzaeg said, repeating Hydro’s forecast for an aluminium market deficit of 1-1.5 million tonnes this year.
“There’s still a lot of aluminium in storage but its gradually reducing. The supply deficit is covered by reserve capacity in China but even with China we have a deficit of 1-1.5 million tonnes globally,” Brandtzaeg said.
He said the trade war between China and U.S. so far had little impact.
“It seems consumers have to pay for this. Margins for U.S. exporters seems to be the same (despite a tariff increase on Chinese aluminium),” Brandtzaeg said.
The aluminium industry has sought immediate resumption of coal supplies to sustain the industry's operations that has been crippled by inadequate power availability.
In a letter to the coal ministry, aluminium producers with captive power units have pointed out how "ad hoc decisions of stopping coal supplies and rakes" has caused a crisis in the entire sector.
Industry body Aluminium Association of India (AAI) has written to the Centre pointing out that coal supplies for captive power plants (CPPs) from Coal India subsidiaries such as Mahanadi Coalfields Ltd (MCL) and South Eastern Coalfields Ltd (SECL) are being diverted to the power sector resulting in a coal supply crunch.
"The CPPs have signed FSA (fuel supply agreements) with CIL, which is a binding agreement with long term coal supply assurance," the AAI letter on October 4 to the Coal Secretary said.
"Any abrupt stoppage of this secured coal supply affects the operations of the industry severely resulting into a grinding halt, thereby impacting the SMEs in downstream sector." it said.
This leads to higher prices of finished products, burdening consumers, said the letter.
It said that the new ad hoc decision without any advance notice has brought down the industry to a standstill and the "industry has been left out with no time to devise any mitigation plan to continue sustainable operations."
The industry body said that aluminium smelters in Odisha require more than 6000MW of power, which is almost double the average power load of the state.
Aluminium smelting requires uninterrupted quality power supply, which can be met only through in-house CPPs, operating 24 hours on all days of the year, it said.
The industry body, which demanded rakes allocation on priority for aluminium industry, pointed out that decision for stopping secured coal supplies should not be taken on an ad hoc basis. "The industry should be given prior notice of one to three months to devise a mitigation plan with respect to coal and power imports." it said.
Chinese copper demand has been so strong in the past few months that top producer Codelco has almost sold out of supplies for next year, well ahead of schedule, according to the chairman of the Chilean state-owned company.
“It’s extremely strong, not only China. It’s extremely strong around the world,” Juan Benavides, who took over as chairman of Codelco in May, said in an interview in London. The wave of buying comes as prices have fallen 15 percent this year amid fears that a trade war between the U.S. and China could stifle global growth.
“The trade war is not good at all,” but “demand is strong, inventories are low, supply is not growing as much as demand,” he said. He sees prices rising above $3 per pound ($6,612 a ton) as demand outpaces supply. Futures are trading at about $6,218 a ton on the London Metal Exchange Tuesday.
Mining companies and investors are increasingly bullish on copper because of limited supply and falling global stockpiles. Codelco has locked in copper-cathode supply contracts with European buyers at a premium of $98 a metric ton over benchmark prices, the highest since 2015. Premiums for contracts signed this year with clients in China and the U.S. are also up by 15 to 17 percent.
This year’s sales are “amazingly good,” said Codelco Vice President Roberto Ecclefield. “It’s the first time you see China, the U.S., and the Europeans very strong. And that is unique in many years.”
In June, Chief Executive Officer Nelson Pizarro announced that the company would bring forward negotiations for supply contracts, which traditionally start in the October-November period. The miner is “almost done” with its annual sales campaign, and is expecting to finish in the next few weeks, Ecclefield said.
“We have heard from our colleagues. In some places they’re saying: look, there’s no copper in the market now for filling all the requirements,” Benavides said. “We see inventories very low.”
Not Enough
Codelco plans to keep its annual output at 1.7 million tons of copper a year, Benavides said. But as its giant century-old operations age and ore grades decline, it needs to invest billions in so-called structural projects to upgrade mines and avoid a decline in production.
The company has a slate of investments planned for the next seven years totaling almost $40 billion, Benavides said.
But he added that the miner would seek to scale back some of its non-essential investments, and could trim $500 million and $1 billion per year from those spending plans. It has set capital expenditure limit of $4 billion a year, he said.
“More or less 60 percent of the projects are structural projects and the other ones are upgrading machinery, sustainability — those are the things we will review,” Benavides said. “Structural projects are not under discussion.”
Higher copper prices and rising demand mean Codelco can self-fund a larger share of its ambitious spending plans, but it’s still not enough, Benavides said. The company will probably issue a new bond of up to $1 billion next year, he said.
President Sebastian Pinera’s government approved a $1 billion financing package through February. After that, Codelco will need to negotiate additional funding with a government that is implementing an austerity plan across all agencies and publicly owned companies in an effort to save $1.2 billion a year over the next four years.
https://www.hellenicshippingnews.com/top-copper-miner-almost-sold-out-on-strong-china-demand/
China produced 5.95 million mt of alumina in Sep. up 3% yoy. Overall output in Jan-Sep came in at 52.11 million mt, up 1.9%
https://news.metal.com/newscontent/100844655/alumina-output-in-sep-gains-3-on-the-year/
Copper producer Atalaya Mining , which is backed by Swiss trading giant Trafigura, is looking for a buyer, two banking sources said on Thursday.
The Cyprus-based miner has hired Canadian investment bank Bank of Montreal to help with the sale, the sources said.
Atalaya’s main copper asset, the Proyecto Riotinto in the Spanish region of Andalucia, was part of a mine complex bought in 1873 by the founders of Rio Tinto from the Spanish government to start the Anglo-Australian mining giant.
Atalaya Mining produced 166,000 tonnes of copper concentrate in 2017 and has a market capitalization of 327 million pounds ($433 million).
Trafigura and Chinese smelter and refiner Yanggu Xiangguang Copper are the main shareholders in Atalaya with 22 percent each, followed by U.S. metals funds Liberty Metals & Mining Holdings and Orion Mine Finance, which hold a combined 28 percent.
Atalaya and Trafigura declined to comment and Yanggu Xiangguang Copper was not immediately available to comment.
Bank of Montreal was also not immediately available to comment.
After Rio Tinto’s ownership, the Proyecto Riotinto mining complex changed hands a few times before Atalaya, then Emed Mining, bought it 20 years ago. It restarted production in 2016.
* China’s copper concentrates and ores imports came in at 1.93 million tonnes in September, the General Administration of Customs said on Friday.
* Figure is all-time monthly high, according to Reuters records, beating the 1.84 million tonnes imported in July. It was also up 16.3 percent from August.
China’s unwrought copper imports rose by 24 percent in September from the previous month to 521,000 tonnes, the highest since March 2016, according to Reuters calculations based on customs data released on Friday.
China’s leading role in financing a wave of new coal plants across Asia is drawing fresh scrutiny as the world’s top climate scientists weigh calling for much deeper cuts in emissions.
China, India, Japan and the Philippines rank among the biggest investors in the 1,380 coal plants under construction or development worldwide, according to a study by the German pressure group Urgewald released Thursday.
The findings add to evidence that Asian companies, often backed by taxpayer money, are stepping up funding for the technology blamed for global warming. A panel of researchers convened by the United Nations next week will release its recommendations for how to limit temperature increases, detailing how to meet a commitment in the 2015 Paris Agreement where almost 200 countries agreed to slash use of fossil fuel.
“Every coal plant that goes online puts a new stumbling block between us and the Paris goals,” said Heffa Schuecking, director of Urgewald.
The report highlights growing scrutiny of the coal industry both by pressure groups and multinational institutions, most of which are working to rein in investment of the most polluting fuels and to promote alternatives. For now, China’s thirst for energy supplies is so strong it pushed up the benchmark coal contract to $100 a ton earlier this week, the most in five years.
Research groups like Urgewald along with CDP and Natural Resources Defense Council are gathering data detailing which companies have the most at stake from tighter rules on climate change. Bank of England Governor Mark Carney is leading a Task Force on Climate-Related Financial Disclosures prodding companies themselves to make transparent the risks they face from environmental rules.
Those efforts sprung up alongside work on the Paris climate agreement, a pact in 2015 where governments everywhere for the first time pledged to limit greenhouse gases. With global carbon emissions from fossil fuels at a record, policy makers are studying how to make quicker reductions and zeroing in on coal as their first target.
Utilities by 2030 would have to consume just a third of the coal they burn now to hold global warming since the start of the industrial era to 1.5 degrees Celsius (2.7 Fahrenheit), according to a draft of a report by the UN’s Intergovernmental Panel on Climate Change. That group of hundreds of top researchers is due to release a report on Oct. 8 in South Korea calling for a massive reduction in burning coal.
Coal currently feeds about 27 percent of the world’s energy demand. That proportion is likely to drop to about 22 percent in 2040 as governments move toward cleaner energy policy, according to the IEA, the Paris-based institution that advises governments on energy. The IPCC was considering a call for coal to supply no more than 7 percent by 2050.
Yet taxpayer funding for new coal plants is growing, according to a report earlier this year by Natural Resources Defense Council, which is based in New York. It found governments in the Group of 20 nations extended a record $13 billion for loans, credits and guarantees backing coal plants last year.
“There’s a huge amount of coal being built with foreign support, and unfortunately the global coal build-out has been largely overlooked as a major climate risk,’’ Han Chen, climate advocate at NRDC.
Export credit agencies such as the Japan Bank for International Cooperation, China Development Bank Corp. and Korea Trade Insurance Corp. were among the biggest supporters. The three biggest destinations for those funds were Indonesia, Bangladesh and Vietnam.
In the Urgewald report, which uses data from the pressure group CoalSwarm, many of the plants are due to be built in Asia. If they’re all installed, they would add 672 gigawatts to the global fleet of coal plants, an increase of a third, the group said.
The World Coal Association has criticized CoalSwarm’s data in the past, saying the actual number of plants being built is much more limited than the group’s data suggests. It cited the Platts World Electric Power Plant Database showing 74 gigawatts of coal plants underway in China, short of the 259 gigawatts that CoalSwarm counted.
https://www.hellenicshippingnews.com/chinas-funding-for-coal-draws-scrutiny-as-climate-concern-grows/
Commodities traders Vitol Group and Trafigura Group Ltd. have entered the bidding process for South Africa’s Optimum Coal, a miner under bankruptcy protection that was once controlled by the Gupta family.
The interest from two of the biggest commodities trading houses underscores the strategic value of Optimum’s annual entitlement to ship 8 million tons of coal through Africa’s largest export terminal for the fuel. While South Africa is well-positioned for exports to India and China, shipments are constrained by limited port capacity. Other investors in the Richards Bay Coal Terminal include mining giants Anglo American Plc, South32 Ltd., and Glencore Plc.
Bids for Optimum are expected to be finalized by the end of November, with due diligence starting on Monday, said Bouwer van Niekerk, a lawyer for the company’s business rescue practitioners. The assets are expected to draw other potential bidders in addition to the interest shown by Vitol and Trafigura, he said.
Local companies Seriti Resources Holdings Pty Ltd. and Exxaro Resources Ltd. expressed interest earlier. Glencore was also considering a bid, two people familiar with the matter said in March.
Optimum was put into business rescue, a form of bankruptcy, after members of the Gupta family fled South Africa. The Gupta’s holding company last year agreed to sell Optimum for 2.97 billion rand ($201 million) to Swiss company Charles King SA. The sale wasn’t completed.
Second Attempt
Bernard Swanepoel, the former head of Harmony Gold Mining Co., said he is part of the Phakamisa Consortium, which is bidding with Trafigura for the assets. A spokeswoman for Trafigura, the second-biggest metals trader and third-largest oil trader behind Vitol and Glencore, declined to comment.
This will be Vitol’s second attempt at acquiring the coal-export allocation. The trader teamed up with Burgh Group Holdings in 2016 to buy it from the company part-owned by the Guptas. The world’s largest independent oil trader walked away from the deal the following year.
Burgh Group won a temporary contract from business rescuers in April to manage Optimum.
https://www.hellenicshippingnews.com/vitol-trafigura-to-bid-for-coal-mines-once-owned-by-guptas/
Charges paid by Glencore PLC on ships entering a large coal port in eastern Australia should be cut by roughly 20%, the country's competition authority said.
The Australian Competition and Consumer Commission on Monday said it has finalized an arbitration dispute between Glencore and the Port of Newcastle over access to a shipping channel and ruled the port should reduce its current charge for ships entering to collect Glencore coal to 61 Australian cents (US$0.43) a gross metric ton from A$0.76 a ton now.
In the arbitration, Newcastle port--the world's biggest coal port--had argued for an increase to A$1.36 a ton while Glencore sought a reduction to A$0.41. Central to the dispute was whether the port should charge for dredging of the shipping channel.
"The ACCC excluded these user-funded amounts from the costs that [Newcastle port] could recover and determined Glencore should pay a lower price, backdated to 2016," said the authority.
https://www.marketwatch.com/story/australia-to-ease-port-charges-for-glencore-2018-10-08
Handan, a major steel producing city in China’s Hebei province, last week released for public comment its detailed plan of production curbs on heavy industries in the 2018/2019 winter season.
The plan, effective from November 1, 2018 to March 31, 2019, targets 10 sectors including steel, coke, tiles and bricks, pharmaceuticals and pesticides that emit volatile organic compounds (VOCs), cement, casting, carbon, glass, ceramics and building materials. There are two transition periods during November 1-14, 2018 and March 16-31, 2019. Air quality levels during the transition period will determine if authorities proceed with winter production curbs.
Steel mills face output curbs of various scales after the central government decided to scrap previous blanket reduction targets this year. Steelmakers across the city would be classified into categories A, B and C based on their emission ratings. This will decide how much capacity those mills are required to cut in winter.
https://news.metal.com/newscontent/100843416/hebei%E2%80%99s-handan-details-winter-production-curbs/
Indonesia sets Oct HBA thermal coal price at $100.89/mt, down 3.7% on month
Indonesia's Ministry of Energy and Mineral Resources set its October thermal coal reference price, also known as Harga Batubara Acuan or HBA, at $100.89/mt, down 3.7% month on month, but up 7.3% year on year.
The ministry had set the price for September at $104.81/mt, and for October 2017 at $93.99/mt.
The HBA is a monthly average price based 25% each on Platts Kalimantan 5,900 kcal/kg GAR assessments, Argus-Indonesia Coal Index 1 (6,500 kcal/kg GAR), Newcastle Export Index (6,322 kcal/kg GAR) and globalCOAL Newcastle (6,000 kcal/kg NAR).
In September, the daily Platts FOB Kalimantan 5,900 kcal/kg GAR coal assessment averaged $73.32/mt, down from $77.68/mt in August, while the daily 7-45 day Platts Newcastle FOB price for coal with a calorific value of 6,300 kcal/kg GAR averaged $114.43/mt, down from $118.29/mt in August.
The HBA price for thermal coal is the basis for determining the prices of 77 Indonesian coal products and calculating the royalty producers have to pay for each metric ton of coal sold.
It is based on 6,322 kcal/kg GAR coal with 8% total moisture content, 15% ash as received and 0.8% sulfur as received.
India produced 52.28 million mt of crude steel over April-September, up 6% from the same period of 2017, amid a rise in domestic demand, latest provisional data from the country's Joint Plant Committee showed.
Hot metal production rose 8.1% year on year to 35.44 million mt over the six-month period, while pig iron production rose 8.8% to 2.97 million mt, the data showed.
Finished steel production totaled 63.76 million mt over April-September, up 4% year on year.
India's domestic demand for steel is forecast to grow 10-11%/year over the next three years as construction activity ramps up, the JPC said.
While steel production increased on all fronts, India's steel trading activity showed signs of contraction, although the country remained a net importer of finished steel.
Imports fell 7.4% on year to 4 million mt in the six-month period, while exports fell 35.2% to 3.14 million mt, the JPC data showed.
State-run JPC is the sole body in India authorized to collect data on the domestic steel and iron industry.
Turkey will introduce quotas on the amount of steel it imports from Oct. 17, with an additional 25 percent duty levied on any imports above the quotas, it said in a filing published by the World Trade Organization on Monday, blaming a surge in imports.
It said it had begun investigating the case for emergency “safeguard” measures in April, after U.S. President Donald Trump imposed a 25 percent tariff on steel. That, and subsequent trade restrictions in other areas, including the European Union, India and Indonesia, had diverted steel towards Turkey.
“These protective policies have been unforeseen developments directly affecting the amount of imports of the product concerned into Turkey,” the WTO document said.
“Turkey has been an attractive market for these steel products that are subject to increasing number of protective measures. Therefore, the measures that have been begun to be applied worldwide ...have triggered an increase of imports of the products concerned into Turkey.”
Turkey’s steel quotas are a provisional safeguard measure, permitted under WTO rules if a country wants to shield a particular industry at risk from a sudden, unforeseen and damaging surge in imports.
It is expected to compensate trade partners who lose out by lowering trade barriers in other areas.
The quota for flat products was set at 3.1 million tonnes, less than half the 8.4 million tonnes that Turkey imported in 2017, the filing said. For long products, the quota was 558,534 tonnes, compared to 2017 imports of 1.3 million tonnes.
The quotas for pipes and tubes was set at 273,901 tonnes, for stainless steel at 139,934 tonnes, and for railway material at 27,044 tonnes, all less than half the 2017 import volume.
The quotas do not apply to hot-rolled stainless steel because it is not produced in Turkey.
India's coal import increased substantially by 35% to 21.1 million tonnes in September, as against 15.61 million tonnes in the corresponding month previous fiscal. The rise in imports comes at a time when the captive power plants in the country are grappling with the issue of coal shortages.
"The increase in coal and coke imports in September is mainly due to higher imports of non-coking coal during the month under review," according to mjunction services, a joint venture between Tata Steel and SAIL.
There was, however, a marginal drop in coking coal imports on a month-on-month basis, it said.
Overall, coal and coke imports during the first half of the current fiscal increased by 13.9% to 119.42 million tonnes, compared to 104.81 million tonnes in the April-September period of previous fiscal, mjunction added.
"With the coal shortage persisting in the power sector, there is high demand for imported material." commenting on the coal import trend, mjunction CEO Vinaya Varma expressed. "This, accompanied by a correction in thermal coal prices in the global market, has led to higher imports in September. If other things remain the same, this trend is likely to continue in October."
Steam coal imports during the first six months of FY2018-19 increased 17.5% to around 82.5 million tonnes, compared to 70.21 million tonnes in the same period previous year, mjunction said.
With the power plants grappling with acute coal shortage, the government has recently directed Coal India and its subsidiaries to give priority to power plants in fuel supply.
Mahanadi Coalfields Ltd (MCL) -- a Coal India arm-- in a recent letter said in view of the acute shortage of coal at power plants, it was decided in the meeting that rakes will be loaded only for power plants.
After meeting the requirement of power plants, CPSUs like RINL, Nalco and SAIL (RSP) are to be loaded till the crisis is over, the letter had said.
The government had earlier said that during 2017-18 coal imports increased to 208.27 million tonnes due to increase in demand by consuming sectors.
The country's coal import fell from 217.7 million tonnes in 2014-15 to 190.9 million tonnes in 2016-17.
The price of steelmaking raw material coking coal jumped nearly 6 percent in China on Monday and coke rose more than 4 percent, buoyed by worries over tighter supply amid longer production curbs as investors returned after a week-long public holiday.
The city of Handan in the smog-prone Hebei province issued a draft winter output reduction plan during the holiday, saying restrictions on heavy industries will run from Nov. 1 to March 31, 2019. That would be a month longer than the previous winter.
The most-active January coking coal contract on the Dalian Commodity Exchange climbed as much as 5.9 percent to 1,332 yuan ($193), its strongest level since Aug. 23.
January coke futures rose 4.2 percent to settle at 2,331.50 yuan a tonne.
The price rally was also driven by concerns over limited supply in major coal hub Shanxi province which has extended its non-heating season production curbs.
China’s environmental ministry’s warned in late September that heavy industrial companies must not flout the nation’s tough emission rules despite Beijing’s move to allow provinces to set their own output restrictions.
“The price hike in the spot market also supported futures, with coking coal prices for long-term contracts rising 70-100 yuan a tonne at some producers,” said a Shandong-based trader.
Rebar steel on the Shanghai Futures Exchange closed up 0.7 percent at 3,971 yuan a tonne, recovering from early losses. Hot-rolled coil gained 1.2 percent to 3,891 yuan.
However, analysts warned of increasing steel inventory, as “steel demand during national holiday was flat, which indicates stockpiles are likely to continue rising and add pressure to steel prices,” brokerage Orient Futures said in a note.
Steel stockpiles held by Chinese traders were at 10 million tonnes on Sept. 28, up from 9.85 million tonnes in the prior week, latest available data from Mysteel consultancy showed.
The Purchasing Managers’ Index (PMI) for the steel sector, an indicator showing industrial operations, fell 1.4 percentage points to 52 percent in September amid declining new orders at steel mills, data from the China Federation of Logistics & Purchasing (CFLP) showed on Monday.
“Steel mills still have very strong incentives to ramp up production amid good weather condition and high steel prices. However, increasing steel prices crimped purchasing intention from downstream sectors,” CFLP said in a statement.
Dalian iron ore futures rose 1 percent to 498 yuan a tonne.
Anyang Iron and Steel Co., Ltd in central China's Henan province is anticipated to realize net profit of 1.5-1.6 billion Yuan
India's iron ore imports increased by 190% from the preceding year to 6.34 million tonnes from April to August,
Chinese steel prices and margins are likely to be "sustainable" in the near term as demand remains robust from low inventories of steel and high prices, said SMM general manager, Ian Roper.
Speaking to delegates at the LME week in London on Monday October 8, he said that seasonality in steel shifted due to winter cuts and disrupted demand in north China, especially in the construction sector.
"An expanding push for cleaner air is likely to result in even greater impact from winter cuts in the fourth quarter of the year," he said. While Chinese authorities decided to avoid blanket cuts this year and would give more exemptions to winter curbs for mills who have upgraded facilities, there is also less room for further productivity gains this winter as mills have already been running at maximum output levels all year.
"The key for winter cuts is the exemptions to demand side impacts," Roper said. Government and infrastructure construction may continue in some regions this winter. On a net basis, he expects steel output cuts to exceed demand cuts this winter, which will be supportive to steel prices and margins.
62% Fe ores could feel the brunt of reduced steel output over winter, especially as supply growth this year has been biased to 62% Fe ores, and Australian miners tend to have very strong shipment volumes in the fourth quarter.
While mills will continue to chase high grade ores; direct charge feed, prices of scrap, pellet and high grade ore will continue to do well, Roper believes.
For domestic iron ore, Roper said that output is "losing its elasticity" due to environmental inspections. As output has laready been restricted for much of the year, further losses over winter is less likely.
Roper also identified electric arc furnaces (EAF) as the major long-term threat to iron ore, as the Chinese government pushes developments of EAF on supply-side reforms.
Australian metallurgical coal miner Peabody declared force majeure on its North Goonyella coking coal Tuesday due to elevated gas levels at the mine site, market sources told S&P Global Platts Tuesday.
The North Goonyella mine, located in the Australian state of Queensland, produces mainly premium mid-vol coking coal for export via the Dalrymple Bay Coal Terminal, south of Mackay, to global seaborne demand centers.
In 2017, 2.9 million mt of coal was sold from the North Goonyella mine.
The United States has granted more than half of the exemptions to its steel import tariffs that Austrian steelmaker Voestalpine and its customers applied for, the company said on Tuesday.
Washington in May announced tariffs of 25 percent on steel imports and 10 percent on aluminium from the European Union, Canada and Mexico.
Of the 4,300 product exemptions that the company and its customers applied for, 2,640 have received a response from the U.S. administration, Voestalpine said. Of those, roughly 2,360 were granted and 280 turned down, it added.
“The economic risk for Voestalpine related to these tariffs has thus reduced ... significantly,” the company said in a statement.
Voestalpine repeated its assessment in June that only up to around 3 percent of its revenue could have been affected by the tariffs. It said at the time that the associated economic risk was “very manageable”.
“We are optimistic that we will receive mainly positive responses to the remaining applications,” Voestalpine added on Tuesday.
Voestalpine supplies sectors including the auto, rail and energy industries with specialty steel products but also produces steel strip. When asked which products had received exemptions, a spokeswoman said they were “across the board” and involved all four of the company’s divisions.
The biggest pure-play coal miner on the ASX says a recent Chinese clampdown on thermal coal imports was no surprise, while analysts expect China's demand for the fuel to remain strong in coming months.
Chinese demand for Australian thermal coal was stronger than expected in the first half of 2018, but softened in September after the Chinese government imposed unofficial restrictions on coal imports in a bid to prop up its domestic coal miners.
Yancoal became the ASX's biggest pure-play exporter by volume when it acquired Rio Tinto's thermal coal mines in 2017, and the company's investor relations general manager James Rickards said the import clamps were becoming a familiar part of "shoulder season" in the Chinese energy sector, which falls between the summer and winter demand peaks.
"China's reduction in coal imports is almost becoming an annual tradition, as the government works to try and support local producers. As a result, it's been both anticipated and prepared for," he said.
"We're likely to see continued fluctuations in pricing across both low and high ash thermal [coal], but the China decision shouldn't cause too significant a ripple."
UBS commodities analyst Lachlan Shaw said the import clamps had not yet sparked a dramatic response from Chinese coal miners.
Curtailments and closures
"[Coal] inventories are on the tight side, we are not seeing a very strong lift in domestic thermal coal production despite the [Chinese] government wanting that," he said recently.
As winter approaches in China, power generators, steel mills and other heavy industry are preparing for another round of operating curtailments and closures as part of government-mandated efforts to reduce air-pollution.
The winter curtailments were expected to be negative for thermal coal demand last year, yet demand proved more robust.
With Chinese coal stocks close to, or below, historic levels, Mr Shaw said he expected Chinese demand for imported thermal coal to remain strong through the coming northern winter.
"In general, thermal coal power generation will be strong through winter, which supports demand," he said.
"I think China's participation in seaborne trade will remain pretty supportive for thermal coal from here.
"The government will try to lift domestic supply through winter to match up with the lift in domestic demand, they will try to keep that balance, but I think that balance will result in the spot price remaining pretty high."
Chinese iron ore futures jumped about 3 percent on Tuesday to their highest since mid-September, supported by market expectation of higher replenish demand at steel mills.
The most-active iron ore contract for January delivery closed up 2.7 percent at 509 yuan ($73.53) a tonne after touching 512 yuan, its highest since Sept. 19.
“Steel mills continued to churn out products during the holiday break and they still have restocking demand in the post-holiday period,” analysts at Huatai Futures said in a note.
Weekly utilisation rates of blast furnaces at steel mills across China were at 68.09 percent as of Oct.5, same as in the prior week, according to data compiled by Mysteel consultancy.
China had a week-long National Day holiday between Oct 1 and 7.
Firm spot iron ore prices also offered momentum to the rally in futures. Benchmark ore with 62 percent iron content stayed at $69.9 a tonne, a level last seen around mid-March, according to data from SteelHome.
Prices for lower grade iron ore, with 58 percent and 52 percent iron content, also climbed to multi-month-highs.
“Market is generally optimistic towards the near-term future. Investors are unlikely to change their opinion unless there is firm data showing further slowdown in new construction starts in the property market,” said a Shanghai-based iron ore trader.
September property data will not be released until Oct. 19. Latest official data showed real estate investment moderated in August on slower construction and home sales, with new construction starts measured by floor area growing at a pace of 26.6 percent from a year earlier.
Other steelmaking raw ingredients extended gains into a second session after soaring more than 5 percent in the previous day.
Coking coal futures on the Dalian Commodity Exchange rose 2.1 percent to 1,333 yuan a tonne, while coke climbed nearly 5 percent to 2,405 yuan a tonne, a level last seen on Sept.11.
China’s Shanxi province, the country’s major coal mining hub, has pledged to cut coking capacity and annual coke output, according to a government statement on Tuesday, in line with a long-term drive to reduce toxic emissions from heavy industry.
This spurred concerns about tight supply of the commodity. Shanxi accounted for 20 percent of the country’s coke output last year.
The most-traded construction steel rebar futures on the Shanghai Futures Exchange gained 2.5 percent to 4,039 yuan.
Weekly steel products inventory rose 847,100 tonnes to 10.85 million tonnes as of last Friday from a week earlier, with rebar stocks up 8.6 percent and hot-rolled coil stocks 9.8 percent higher, according to Mysteel data.
https://www.hellenicshippingnews.com/dalian-iron-ore-hits-nearly-3-week-high-on-restocking-outlook/
Procter & Gamble Co (PG.N) was informed on Tuesday that it is now exempt from the 25 percent U.S. tariff levied on imported Japanese and Swedish steel that is used in its Gillette and Venus razor blades, a company spokesman told Reuters.
The exemption notification, from the Department of Commerce’s Bureau of Industry and Security, came nearly four months after P&G’s biggest razor rival, Edgewell Personal Care Co (EPC.N), received an exemption. Edgewell, owner of the Wilkinson Sword and Schick brands, filed an exemption application in late March and told Reuters it was informed it was granted the week of June 18.
“There was definitely a financial impact to the company, but we haven’t disclosed any numbers,” P&G spokesman Damon Jones said of the effect of the steel tariff. Gillette and Venus are the biggest components of P&G’s grooming business, which accounted for about 10 percent of global net sales in fiscal 2018, ended July 31.
“It wasn’t materially market-moving, but given the competitiveness of this industry we think it is important and significant,” Jones said.
U.S. President Donald Trump’s administration imposed tariffs on steel imports from most countries in March, and on the European Union in June.
P&G and Edgewell both said that U.S. steel manufacturers cannot supply the high-quality grade of steel needed to make precision razor blades, obliging them to pay higher prices for steel or seek exemptions.
P&G, the world’s No. 1 personal care goods company, which has been struggling with soaring raw material and transportation costs this year, chose not to pass the 25 percent surtax onto consumers at a time of intense competition in the industry.
The company has been cutting prices at its grooming business, hoping to claw back market share from upstart shaving brands such as Harry’s and Dollar Shave Club. Like other consumer goods companies, P&G has been squeezed this year between pressure to cut prices and surging input costs.
Jon Moeller, P&G’s chief financial officer, told Reuters in August that the tariffs on steel imports were the company’s biggest trade-related concern.
A company spokesman told Reuters in July that products sold in Canada - from Febreze candles to Gillette shaving foam - would be affected by retaliatory tariffs on U.S.-made goods after Canadian authorities rejected a request for exemptions. The company has also identified more than a dozen products that could be hurt by the latest round of U.S. tariffs as tensions with China rise.
Shanxi province, a major coal mining hub in northern China, vowed to cut coking capacity and annual coke output,
The American Iron and Steel Institute reported the United States received permit applications for 2.73 million tonnes of steel in September, an 8.7% decrease as compared to 3 million tonnes imported the previous month. It was a 7.6% decline from August's preliminary permit applications.
Imports of foreign-made steel have declined by 10.6% so far this year, largely as a result of the Section 232 tariffs of 25%.
In September, imports continued to decline, capturing only 21% of the market share, according to the U.S. Commerce Department's most recent Steel Import Monitoring and Analysis data.
In September, imports of light shapes bars grew by 103%, hot rolled sheets by 35%, plates in coils by 24%, sheets and strip all other metallic coatings by 22%, standard pipe by 19% and cold rolled sheets by 12%.
South Korea, Turkey, Germany, Taiwan area, and Japan were the largest offshore suppliers of steel in September. So far this year, imports have fallen by 21% from South Korea, 14% from Japan and 49% from Turkey.
During the first nine months of the year, the United States imported 26.5 million tonnes of steel. That included 20.1 million tonnes of finished steel that would require no further processing by workers in the United States, a 12.1% drop as compared to the same period in 2017.
Imports have grabbed about 24% of the U.S. market share so far this year.
Russia exported 144 million tonnes of coal over January-September, up by 3.82% from a year ago, showed data from the Energy Ministry
CEO Elizabeth Gaines told shareholders on Thursday that the share buy-back was a natural extension of the company’s capital allocation focus, which has shifted from debt reduction following the rapid de-gearing of the balance sheet, and the successful execution of Fortescue’s capital management strategy.
“With our continued strong operating performance, and new investments under way, the purchase of our own shares, funded out of operating cash flows, maintains our disciplined balance sheet management. This is consistent with our clear business strategy of investing in our core iron-ore business while pursuing growth and development in delivering returns to our shareholders.”
The buy-back will not require shareholder approval and will start after the release of the company’s quarterly report, on October 25.
http://www.miningweekly.com/article/fortescue-launches-a500m-share-buy-back-2018-10-11
China’s iron ore imports rose to their highest level in four months in September, according to customs data issued on Friday, as steel mills ramped up output ahead of winter production restrictions.
Arrivals of steelmaking ingredient iron ore increased to 93.47 million tonnes last month from 89.35 million tonnes in August, but were down from a record 102.83 million tonnes a year ago, according to data from General Administration of Customs.
September is typically a high season for construction activity in China, with increased demand for both steel products and raw materials.
Earlier China Iron and Steel Association (CISA) data showed that average daily crude steel production at its member mills rose to 1.98 million tonnes over Sept. 1-20, up from 1.91 million tonnes in August and 1.94 million tonnes in July.
“Production restrictions last month were not very strict, so steel mills seized the chance to ramp up output before more intense rules kick in,” said Wang Yilin, an analyst at Sinosteel Futures.
Blast furnace utilisation rates at steel mills across China reached 68.23 percent in mid-September, the highest in two months, and have been hovering around 68 percent since then, according to data from Mysteel consultancy, as mills rushed to boost output before the production restrictions kick in.
The environment ministry has scrapped blanket cuts from its final winter anti-pollution plan, allowing local authorities to decide the rates and timeframes for individual cuts.
Top steelmaking city Tangshan has started production curbs from Oct. 1, while Handan city - also in smog-prone Hebei province - plans to enforce cuts from Nov. 1.
The winter anti-pollution campaign may also expand to broader regions this year, as governments in the Yangtze River Delta, including the No.2 steel producing province of Jiangsu, work on a similar plan to northern areas.
That could crimp operations at steel mills and activity at downstream users, further curbing demand for steelmaking raw materials including iron ore.
“Steel mills will keep only small inventory when winter cuts kick in, meaning their restocking demand will be dynamic,” said Wang.
Vessel-tracking and port data compiled by Refinitiv suggests China will import about 83.46 million tonnes of seaborne iron ore in October, a slight pullback from 85.63 million in September.
For the first nine months this year, China bought a total of 803.34 million tonnes of iron ore, customs data showed.
Sintering machines, shaft furnaces and lime kilns in Tangshan were required to cut capacity by half from 18:00 CST on Thursday October 11 to 24:00 CST on Thursday October 18, SMM learned. The city government imposed the requirement in face of potential heavy pollution during that period.
Sintering machines with denitrification facilities under installation will be exempted from the restriction. These include a sintering machine of 198 m² at Kaiheng Steel, one of 265 m² at Tangshan Stainless Steel, two of 300 m² at Yanshan Iron & Steel, a 265 m² and 240 m² at Hebei Jinxi Iron & Steel, as well as a 230 m² at Delong Steel.
Brazil’s Vale, the world’s top iron ore producer, has achieved its target of halving net debt to $10 billion and will now focus on increasing returns to shareholders, Chief Executive Fabio Schvartsman told the Financial Times in an interview.
Brazilian mining company Vale S.A.'s CEO Fabio Schvartsman speaks during the 2018 Latin America Investment Conference in Sao Paulo, Brazil, January 30, 2018. REUTERS/Nacho Doce
“There is nothing more than can or should be done,” Schvartsman said, adding buybacks were the best investment the company could make at the current time.
Vale did not immediately respond to a request for comment.
The company, whose cash flow has surged in recent quarters as iron ore prices rallied, has been mulling whether to spend those funds on diversification or remunerating shareholders through dividend hikes or buybacks, sources familiar with the matter told Reuters earlier this month.
Vale is scheduled to post its third quarterly earnings on Oct. 24.
